UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2002
--------------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
-------------- -------------------
Commission file number 1-8483
UNOCAL CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 95-3825062
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2141 ROSECRANS AVENUE, SUITE 4000, EL SEGUNDO, CALIFORNIA 90245
(Address of principal executive offices)
(Zip Code)
(310) 726-7600
(Registrant's Telephone Number, Including Area Code)
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
------- -------
Number of shares of Common Stock, $1 par value, outstanding as of
October 31, 2002: 257,896,541
TABLE OF CONTENTS
PAGE
Glossary.................................................................... ii
PART I
Item 1. Financial Statements
Consolidated Earnings............................................. 1
Consolidated Balance Sheet........................................ 2
Consolidated Cash Flows........................................... 3
Notes to Financial Statements..................................... 4
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations....................... 29
Operating Highlights ............................................... 33
Item 3. Quantative and Qualitative Disclosures About Market Risk............ 45
Item 4. Controls and Procedures............................................. 50
PART II
Item 1. Legal Proceedings................................................... 50
Item 6. Exhibits and Reports on Form 8-K.................................... 51
SIGNATURE................................................................... 52
CERTIFICATIONS.............................................................. 53
EXHIBIT INDEX............................................................... 55
GLOSSARY
Below are certain definitions of key terms that may be in use in this Form 10-Q
report.
M Thousand Bbl Barrels
MM Million Cf/d Cubic feet per day
B Billion Cfe/d Cubic feet of gas
equivalent per day
CF Cubic feet Btu British thermal units
BOE Barrels of oil equivalent DD&A Depreciation, depletion
and amortization
Liquids Crude oil, condensate and NGLs NGLs Natural gas liquids
Bbl/d Barrels per day
o API Gravity is a measurement of the gravity (density) of crude oil and
other liquid hydrocarbons by a system recommended by the American Petroleum
Institute ("API"). The measuring scale is calibrated in terms of "API
degrees." The higher the API gravity, the lighter the oil.
o Bilateral institution refers to a country specific institution, which lends
funds primarily to promote the export of goods from that country. Examples
of bilateral institutions are Ex-Im (U.S.), Hermes (Germany), SACE (Italy),
COFACE (France), and JBIC (Japan).
o BOE A term used to quantify oil and natural gas amounts using the same
measurement. Gas volumes are converted to barrels of oil on the basis of
energy content, where the volume of natural gas that when burned produces
the same amount of heat as a barrel of oil (6,000 cubic feet of gas equals
one barrel of oil).
o British Thermal Units ("Btu") is a measure of the amount of heat required
to raise the temperature of one pound of water one degree Fahrenheit.
o Delineation or appraisal well is a well drilled in an unproven area
adjacent to a discovery well to define the boundaries of the reservoir.
o Development well is a well drilled within the proved area of an oil or
natural gas reservoir to a depth of a stratigraphic horizon known to be
productive.
o Dry hole is a well believed to be incapable of producing hydrocarbons in
sufficient commercial quantities to justify future capital expenditures for
completion and additional infrastructure.
o Economic interest method pursuant to production sharing contracts is a
method by which the Company's share of the cost recovery revenue and the
profit revenue is divided by market oil and gas prices and represents the
volume that the Company is entitled to. The lower the commodity price, the
higher the volume entitlement, and vice versa.
o Exploratory well is a well drilled to find and produce oil or natural gas
reserves that is not a development well.
o Farm-in or farm-out is an agreement whereby the owner of a working interest
in an oil and gas lease assigns the working interest or a portion thereof
to another party who desires to drill on the leased acreage. The assignor
usually retains a royalty or reversionary interest in the lease. The
interest received by an assignee is a "farm-in," while the interest
transferred by the assignor is a "farm-out."
o Field is an area consisting of a single reservoir or multiple reservoirs
all grouped on or related to the same individual geological structural
feature or stratigraphic condition.
o Floating Production Storage and Offloading ("FPSO") technology refers to
the use of a vessel that is stationed above or near an offshore oil field.
Produced fluids from subsea completion wells are brought by flowlines to
the vessel where they are separated, treated, stored and then offloaded to
another vessel for transportation.
o Gross acres or gross wells are the total acres or wells in which a working
interest is owned.
ii
o Hydrocarbons are organic compounds of hydrogen and carbon atoms that form
the basis of all petroleum products.
o Lifting is the amount of liquids each working-interest partner takes
physically. The liftings may actually be more or less than actual
entitlements that are based on royalties, working interest percentages, and
a number of other factors.
o Liquefied Natural Gas ("LNG") is a gas, mainly methane, which has been
liquefied in a refrigeration and pressure process to facilitate storage and
transportation.
o Liquefied Petroleum Gas ("LPG") is a mixture of butane, propane and other
light hydrocarbons. At normal temperature it is a gas, but it can be cooled
or subjected to pressure to facilitate storage and transportation.
o Multilateral institution refers to an institution with shareholders from
multiple countries that lends money for specific development reasons.
Examples of multilateral institutions are International Finance Corporation
("IFC"), European Bank for Reconstruction and Development ("EBRD"), and
Asian Development Bank ("ADB").
o Natural Gas Liquids ("NGLs") are primarily ethane, propane, butane and
natural gasolines which can be extracted from wet natural gas and become
liquid under various combinations of increasing pressure and lower
temperature.
o Net acreage and net oil and gas wells are obtained by multiplying gross
acreage and gross oil and gas wells by the Company's working interest
percentage in the properties.
o Net pay is the amount of oil or gas saturated rock capable of producing oil
or gas.
o Production Sharing Contract ("PSC") is a contractual agreement between the
Company and a host government whereby the Company, acting as contractor,
bears all exploration costs, development and production costs in return for
an agreed upon share of the proceeds from the sale of production.
o Producible well is a well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of
such production exceed production expenses and taxes.
o Prospective acreage is lease acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of oil and natural gas.
o Proved acreage is acreage that is allocated to producing wells or wells
capable of production or to acreage that is being developed.
o Reservoir is a porous and permeable underground formation containing oil
and/or natural gas enclosed or surrounded by layers of less permeable rock
and is individual and separate from other reservoirs.
o Subsea tieback is a well with the wellhead equipment located on the bottom
of the ocean.
o Take-or-Pay is a type of contract clause where specific quantities of a
product must be paid for, even if delivery is not taken. Normally, the
purchaser has the right in following years to take product that had been
paid for but not taken.
o Trend or Play is an area or region of concentrated activity with a group of
related fields and prospects.
o Working interest is the percentage of ownership that the Company has in a
joint venture, partnership, consortium, project or acreage.
ii
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONSOLIDATED EARNINGS (UNAUDITED) UNOCAL CORPORATION
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
------------------------------------------------------
Millions of dollars except per share amounts 2002 2001 2002 2001
------------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ 1,287 $ 1,573 $ 3,660 $ 5,463
Interest, dividends and miscellaneous income (loss) (3) 8 17 27
Gain (loss) on sales of assets 1 (2) 2 (1)
------------------------------------------------------------------------------------------------------------------------------
Total revenues 1,285 1,579 3,679 5,489
Costs and other deductions
Crude oil, natural gas and product purchases 401 617 1,124 2,141
Operating expense 314 352 914 1,011
Administrative and general expense 34 25 114 96
Depreciation, depletion and amortization 245 246 724 714
Impairments 6 - 27 -
Dry hole costs 40 53 81 140
Exploration expense 60 61 180 172
Interest expense 40 48 134 145
Property and other operating taxes 7 19 41 60
Distributions on convertible preferred securities of subsidiary trust 8 8 24 24
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Total costs and other deductions 1,155 1,429 3,363 4,503
Earnings from equity investments 35 37 123 128
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Earnings from continuing operations before
income taxes and minority interests 165 187 439 1,114
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Income taxes 68 77 203 447
Minority interests (2) 8 2 38
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Earnings from continuing operations 99 102 234 629
Discontinued operations
Refining, marketing and transportation
Gain on disposal (net of tax) - - 1 16
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Earnings from discontinued operations - - 1 16
Cumulative effect of accounting change - - - (1)
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Net earnings $ 99 $ 102 $ 235 $ 644
==============================================================================================================================
Basic earnings per share of common stock (a)
Continuing operations $ 0.41 $ 0.42 $ 0.96 $ 2.59
Net earnings $ 0.41 $ 0.42 $ 0.96 $ 2.65
Diluted earnings per share of common stock (b)
Continuing operations $ 0.41 $ 0.42 $ 0.96 $ 2.53
Net earnings $ 0.41 $ 0.42 $ 0.96 $ 2.59
Cash dividends declared per share of common stock $ 0.20 $ 0.20 $ 0.60 $ 0.60
------------------------------------------------------------------------------------------------------------------------------
(a) Basic weighted average shares outstanding (in thousands) 244,664 243,601 244,503 243,426
(b) Diluted weighted average shares outstanding (in thousands) 245,226 244,566 245,378 256,812
See Notes to the Consolidated Financial Statements.
-1-
CONSOLIDATED BALANCE SHEET UNOCAL CORPORATION
At September 30, At December 31,
------------------------------------------
Millions of dollars 2002 (a) 2001
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Assets
Current assets
Cash and cash equivalents $ 275 $ 190
Accounts and notes receivable - net 690 847
Inventories 103 102
Deferred income taxes 97 123
Other current assets 20 33
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Total current assets 1,185 1,295
Investments and long-term receivables - net 1,549 1,405
Properties - net (b) 7,784 7,514
Deferred income taxes 179 128
Other assets 103 83
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Total assets $ 10,800 $ 10,425
===================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ 873 $ 823
Taxes payable 175 249
Dividends payable 49 49
Interest payable 46 49
Current portion of environmental liabilities 126 124
Current portion of long-term debt and capital leases 8 9
Other current liabilities 181 119
-------------------------------------------------------------------------------------------------------------------
Total current liabilities 1,458 1,422
Long-term debt and capital leases 3,070 2,897
Deferred income taxes 731 627
Accrued abandonment, restoration and environmental liabilities 595 590
Other deferred credits and liabilities 706 724
Subsidiary stock subject to repurchase 111 70
Minority interests 425 449
Company-obligated mandatorily redeemable convertible preferred
securities of a subsidiary trust holding solely parent debentures 522 522
Common stock ($1 par value, shares authorized: 750,000,000 (c)) 255 255
Capital in excess of par value 573 551
Unearned portion of restricted stock issued (23) (29)
Retained earnings 2,977 2,888
Accumulated other comprehensive income (147) (88)
Notes receivable - key employees (42) (42)
Treasury stock - at cost (d) (411) (411)
-------------------------------------------------------------------------------------------------------------------
Total stockholders' equity 3,182 3,124
-------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $ 10,800 $ 10,425
===================================================================================================================
(a) Unaudited
(b) Net of accumulated depreciation, depletion and amortization of: $ 12,149 $ 11,648
(c) Number of shares outstanding (in thousands) 244,661 243,998
(d) Number of shares (in thousands) 10,623 10,623
See Notes to the Consolidated Financial Statements.
-2-
CONSOLIDATED CASH FLOWS (UNAUDITED) UNOCAL CORPORATION
For the Nine Months
Ended September 30,
---------------------------------
Millions of dollars 2002 2001
--------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net earnings $ 235 $ 644
Adjustments to reconcile net earnings to
net cash provided by operating activities
Depreciation, depletion and amortization 724 714
Impairments 27 -
Dry hole costs 81 140
Amortization of exploratory leasehold costs 74 69
Deferred income taxes 25 113
(Gain) loss on sales of assets (pre-tax) (2) 1
(Gain) on disposal of discontinued operations (pre-tax) (2) (25)
Earnings applicable to minority interests 2 38
Other (56) 115
Working capital and other changes related to operations
Accounts and notes receivable 160 360
Inventories (2) (4)
Accounts payable 44 (194)
Taxes payable 4 (24)
Other (82) (167)
--------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 1,232 1,780
--------------------------------------------------------------------------------------------------------------------------
Cash Flows from Investing Activities
Capital expenditures (includes dry hole costs) (1,248) (1,257)
Major acquisitions - (536)
Proceeds from sales of assets 61 26
Proceeds from sale of discontinued operations 3 25
--------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (1,184) (1,742)
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Cash Flows from Financing Activities
Long-term borrowings 437 467
Reduction of long-term debt and capital lease obligations (267) (221)
Minority interests (6) (17)
Proceeds from issuance of common stock 19 14
Dividends paid on common stock (147) (146)
Other 1 1
--------------------------------------------------------------------------------------------------------------------------
Net cash provided by financing activities 37 98
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Net increase in cash and cash equivalents 85 136
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Cash and cash equivalents at beginning of year 190 235
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Cash and cash equivalents at end of period $ 275 $ 371
==========================================================================================================================
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 136 $ 150
Income taxes (net of refunds) $ 211 $ 354
See Notes to the Consolidated Financial Statements.
-3-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. General
The consolidated financial statements included in this report are unaudited and,
in the opinion of management, include all adjustments necessary for a fair
presentation of financial position and results of operations. All adjustments
are of a normal recurring nature. Such financial statements are presented in
accordance with the Securities and Exchange Commission's ("SEC") disclosure
requirements for Form 10-Q.
These interim consolidated financial statements should be read in conjunction
with the consolidated financial statements and the related notes filed with the
SEC in Unocal Corporation's amended 2001 Annual Report on Form 10-K/A.
For the purpose of this report, Unocal Corporation ("Unocal") and its
consolidated subsidiaries, including Union Oil Company of California ("Union
Oil"), are referred to as the "Company".
The consolidated financial statements of the Company include the accounts of
subsidiaries in which a controlling interest is held. Investments in entities
without a controlling interest are accounted for by the equity method or cost
basis. Under the equity method, the investments are stated at cost plus the
Company's equity in undistributed earnings and losses after acquisition. Income
taxes estimated to be payable when earnings are distributed are included in
deferred income taxes.
Results for the nine months ended September 30, 2002, are not necessarily
indicative of future financial results. Certain items in the prior year
financial statements have been reclassified to conform to the 2002 presentation.
2. Accounting Changes
Effective January 1, 2002, the Company adopted Statement of Financial Accounting
Standards ("SFAS") No. 142, "Goodwill and Other Intangible Assets". SFAS No. 142
addresses accounting for goodwill and identifiable intangible assets subsequent
to their initial recognition, eliminates the amortization of goodwill and
provides specific steps for testing the impairment of goodwill. Separable
intangible assets that are not deemed to have an indefinite life will continue
to be amortized over their useful lives. SFAS No. 142 also eliminates
amortization of the excess of cost over the underlying equity in the net assets
of an equity method investee that is recognized as goodwill. The adoption of the
statement did not have a material effect on the Company's financial position and
results of operations.
Effective January 1, 2002, the Company also adopted SFAS No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets", which addresses financial
accounting and reporting for the impairment or disposal of long-lived assets.
SFAS No. 144 supersedes SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of", and the
accounting and reporting provisions of Accounting Principles Board Opinion No.
30, "Reporting the Results of Operations--Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions". The adoption of SFAS No. 144 did not have a material
effect on the Company's financial position and results of operations.
The Company has adopted SFAS No. 145, "Rescission of SFAS No. 4, 44, and 64,
Amendment of SFAS No. 13, and Technical Corrections." This statement rescinds
SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt", and an
amendment of that statement, SFAS No. 64, "Extinguishments of Debt Made to
Satisfy Sinking-Fund Requirements". This statement also rescinds or amends
other existing authoritative pronouncements to make various technical
corrections, clarify meanings, or describe their applicability under changed
conditions. The adoption of SFAS No. 145 did not have a material effect on the
Company's financial position and results of operations.
-4-
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities". This statement provides guidance on the
recognition and measurement of liabilities associated with disposal activities
and is effective for the Company on January 1, 2003. The Company does not expect
the adoption of SFAS No. 146 to have a significant impact on its financial
position and results of operations.
In August 2001, the FASB issued SFAS No 143, "Accounting for Asset Retirement
Obligations". It is effective for fiscal years beginning after June 15, 2002,
and it requires entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred, as a capitalized
cost of the long-lived asset and to depreciate it over the useful life of the
asset. The Company is currently in the process of evaluating the impact that
SFAS No. 143 will have on its financial position and results of operations.
3. Other Financial Information
During the third quarters of 2002 and 2001, approximately 24 percent and 32
percent, respectively, of total sales and operating revenues were attributable
to the resale of liquids and natural gas purchased from others in connection
with marketing activities. For the nine months ended September 30, 2002 and
2001, these percentages were approximately 23 percent and 32 percent,
respectively. Related purchase costs are classified as expense in the crude oil,
natural gas and product purchase category on the consolidated earnings
statement. The current year percentage decreases were principally due to lower
purchases of domestic crude oil from third parties for resale, reflecting
management's continued efforts to decrease its outside crude oil purchases for
resale due to increased volatility in the oil markets.
Capitalized interest totaled $14 million and $8 million for the third quarters
of 2002 and 2001, respectively, and $33 million and $19 million for the nine
months ended September 30, 2002 and 2001, respectively. The increase was
primarily due to the capitalized interest related to the West Seno oil and gas
development project in the deepwater Kutei Basin, offshore East Kalimantan,
Indonesia, and the Mad Dog oil development project in the deepwater Gulf
of Mexico.
Exploration expense on the consolidated earnings statement consisted of the
following:
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
------------------------------------------
Millions of dollars 2002 2001 2002 2001
--------------------------------------------------------------------------------
Exploration operations $ 18 $ 22 $ 66 $ 62
Geological and geophysical 10 11 29 30
Amortization of exploratory leases 29 24 74 69
Leasehold rentals 3 4 11 11
--------------------------------------------------------------------------------
Exploration expense $ 60 $ 61 $ 180 $ 172
================================================================================
4. Restructuring
In June 2002, the Company adopted a restructuring plan that resulted in the
accrual of a $19 million pre-tax restructuring charge. The charge included the
estimated costs of terminating approximately 200 employees in the Company's
Sugar Land, Texas, office and field locations. The restructuring plan involves
organizational changes to eliminate unnecessary work processes in the Company's
Gulf Region business unit, which is part of the U.S. Lower 48 operations in the
Exploration and Production segment.
The restructuring charge was reflected in the operating expense line on the
consolidated earnings statement and included approximately $14 million for
termination costs to be paid to the employees over time, about $3 million for
outplacement and other costs and about $2 million for benefit plan curtailment
costs. All of the affected employees had been terminated as of September 30,
2002.
-5-
5. Impairments
The Company, as part of its regular assessment, reviewed its developed and
undeveloped oil and gas properties and other long-lived assets for possible
impairment. In the third quarter of 2002, the Company recorded a pre-tax charge
of $6 million, or $4 million after-tax, primarily due to impairment related to a
U.S. pipeline company, in which the Company owns an equity interest. The
Company's equity interests in petroleum pipeline companies are part of the
Midstream segment. In the nine months period of 2002, the Company recorded a
pre-tax charge of $27 million, or $17 million after-tax, for the impairment of
oil and gas fields in Alaska and the Gulf of Mexico region and the
aforementioned pipeline company impairment. The impairment in Alaska was $19
million pre-tax, or $12 million after-tax.
6. Income Taxes
Income taxes on earnings from continuing operations for the third quarter and
nine months periods of 2002 were $68 million and $203 million, respectively,
compared with $77 million and $447 million for the comparable periods of 2001.
The effective income tax rates for the third quarter and nine months periods of
2002 were 41 percent and 46 percent, respectively, compared with 41 percent and
40 percent for the comparable periods of 2001.
The higher effective income tax rate for the nine months period of 2002, as
compared with the same period a year ago, reflected the effect of changes in the
mix of domestic losses in 2002 and earnings in 2001 coupled with foreign
earnings in both years, which are generally taxed at higher rates, along with
foreign currency effects, primarily in Thailand.
In 2002, the Company anticipates electing to carryback a current year domestic
source net operating loss for a refund of prior year federal income tax paid.
7. Earnings Per Share
The following are reconciliations of the numerators and denominators of the
basic and diluted earnings per share ("EPS") computations for earnings from
continuing operations for the third quarters and nine months ended September 30,
2002 and 2001:
Earnings Shares Per Share
Millions except per share amounts (Numerator) (Denominator) Amount
---------------------------------------------------------------------------------------------------------------------------
Three months ended September 30, 2002
Earnings from continuing operations $ 99 244.6
Basic EPS $ 0.41
=============
Effect of dilutive securities
Options and common stock equivalents 0.6
--------------------------------
Diluted EPS 99 245.2 $ 0.41
=============
Distributions on subsidiary trust preferred securities (after-tax) 7 12.3
--------------------------------
Antidilutive $ 106 257.5 $ 0.41
Three months ended September 30, 2001
Earnings from continuing operations $ 102 243.6
Basic EPS $ 0.42
=============
Effect of dilutive securities
Options and common stock equivalents 1.0
--------------------------------
Diluted EPS 102 244.6 $ 0.42
=============
Distributions on subsidiary trust preferred securities (after-tax) 7 12.3
--------------------------------
Antidilutive $ 109 256.9 $ 0.42
---------------------------------------------------------------------------------------------------------------------------
-6-
Not included in the computation of diluted EPS for the three months ended
September 30, 2002 and 2001, were options outstanding to purchase approximately
8 million and 5.2 million shares, respectively, of common stock. These options
were not included in the computation as the exercise prices were greater than
average market prices of the common shares during the respective quarters.
Earnings Shares Per Share
Millions except per share amounts (Numerator) (Denominator) Amount
---------------------------------------------------------------------------------------------------------------------------
Nine months ended September 30, 2002
Earnings from continuing operations $ 234 244.5
Basic EPS $ 0.96
=============
Effect of dilutive securities
Options and common stock equivalents 0.9
--------------------------------
Diluted EPS 234 245.4 $ 0.96
=============
Distributions on subsidiary trust preferred securities (after-tax) 20 12.3
--------------------------------
Antidilutive $ 254 257.7 $ 0.99
Nine months ended September 30, 2001
Earnings from continuing operations $ 629 243.4
Basic EPS $ 2.59
=============
Effect of dilutive securities
Options and common stock equivalents 1.1
--------------------------------
629 244.5 $ 2.57
Distributions on subsidiary trust preferred securities (after-tax) 20 12.3
--------------------------------
Diluted EPS $ 649 256.8 $ 2.53
=============
---------------------------------------------------------------------------------------------------------------------------
The diluted EPS computation for the nine months ended September 30, 2002 and
2001, did not include options outstanding to purchase approximately 5.8 million
and 6.3 million shares, respectively, of common stock. These options were not
included in the computation as the exercise prices were greater than the
year-to-date average market price of the common shares.
Basic and diluted earnings per common share for discontinued operations were as
follows:
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
-------------------------------------------------------
Millions except per share amounts 2002 2001 2002 2001
----------------------------------------------------------------------------------------------------------------------
Basic earnings per share of common stock:
Discontinued operations:
Earnings from discontinued operations $ - $ - $ 1 $ 16
Weighted average common shares outstanding 244.6 243.6 244.5 243.4
Earnings from discontinued operations $ - $ - $ - $ 0.06
Dilutive earnings per share of common stock:
Discontinued operations:
Earnings from discontinued operations $ - $ - $ 1 $ 16
Weighted average common shares outstanding 245.2 244.6 245.4 256.8
Earnings from discontinued operations $ - $ - $ - $ 0.06
-7-
8. Comprehensive Income
The Company's comprehensive income was:
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
---------------------------------------------------
Millions of dollars 2002 2001 2002 2001
--------------------------------------------------------------------------------------------------------------------------
Net earnings $ 99 $ 102 $ 235 $ 644
Cumulative effect of change in accounting principle
SFAS No. 133 adoption (a) - - - (59)
Change in unrealized loss on hedging instruments (b) (26) 17 (35) 43
Reclassification adjustment for settled hedging contracts (c) - (3) (1) 23
Unrealized foreign currency translation adjustments (55) (24) (23) (40)
--------------------------------------------------------------------------------------------------------------------------
Total comprehensive income $ 18 $ 92 $ 176 $ 611
==========================================================================================================================
(a) Net of tax expense (benefit) of: - - - (36)
(b) Net of tax expense (benefit) of: (15) 10 (21) 25
(c) Net of tax expense (benefit) of: - (2) - 14
9. Cash and Cash Equivalents
At September 30, At December 31,
----------------------------------------
Millions of dollars 2002 2001
-------------------------------------------------------------------------------
Cash $ 9 $ 12
Time deposits 167 123
Restricted cash 4 5
Marketable securities 95 50
-------------------------------------------------------------------------------
Cash and cash equivalents $ 275 $ 190
===============================================================================
10. Long Term Debt and Credit Agreements
During the nine months period of 2002, the Company's consolidated debt,
including the current portion, increased by $173 million. This net increase
included $437 million in new commercial paper borrowings, the proceeds of which
were used to refinance maturing debt and for general corporate purposes. The
commercial paper had a weighted average interest rate of 2.74 percent at
September 30, 2002. The Company retired $152 million of maturing medium-term
notes during the nine months period of 2002. In February 2002, the Company's
Northrock Resources Ltd. subsidiary redeemed its $35 million "Series A" and $40
million "Series B" senior U.S. dollar-denominated notes, which bore interest of
6.54 percent and 6.74 percent, respectively. The Company's Pure Resources, Inc.
("Pure") subsidiary reduced its long-term debt, included in the Company's
consolidated debt, by $34 million principally due to a decrease in borrowing
under its revolving credit facilities. Pure's debt was $553 million at September
30, 2002. Neither Unocal nor Union Oil guarantees any of Pure's debt.
11. Accrued Abandonment, Restoration and Environmental Liabilities
At September 30, 2002, the Company had accrued $479 million for the estimated
future costs to abandon and remove wells and production facilities. At December
31, 2001, the Company had accrued $477 million. The total costs for these
abandonments are predominantly accrued on a unit-of-production basis and were
estimated to be approximately $725 million and $670 million at September 30,
2002 and December 31, 2001, respectively. This estimate was derived in large
part from abandonment cost studies performed by independent third party firms
and is used to calculate the amount to be amortized. The Company's reserves for
environmental remediation obligations at September 30, 2002 totaled $242
million, of which $126 million were included in current liabilities. This
compared with $237 million at December 31, 2001, of which $124 million were
included in current liabilities.
-8-
12. Commitments and Contingencies
The Company has contingent liabilities with respect to material existing or
potential claims, lawsuits and other proceedings, including those involving
environmental, tax and other matters, certain of which are discussed more
specifically below. The Company accrues liabilities when it is probable that
future costs will be incurred and such costs can be reasonably estimated. Such
accruals are based on developments to date, the Company's estimates of the
outcomes of these matters and its experience in contesting, litigating and
settling other matters. As the scope of the liabilities becomes better defined,
there will be changes in the estimates of future costs, which could have a
material effect on the Company's future results of operations and financial
condition or liquidity.
Environmental matters
The Company is subject to loss contingencies pursuant to federal, state, local
and foreign environmental laws and regulations. These include existing and
possible future obligations to investigate the effects of the release or
disposal of certain petroleum, chemical and mineral substances at various sites;
to remediate or restore these sites; to compensate others for damage to property
and natural resources, for remediation and restoration costs and for personal
injuries; and to pay civil penalties and, in some cases, criminal penalties and
punitive damages. These obligations relate to sites owned by the Company or
others and are associated with past and present operations, including sites at
which the Company has been identified as a potentially responsible party ("PRP")
under the federal Superfund laws and comparable state laws. Liabilities are
accrued when it is probable that future costs will be incurred and such costs
can be reasonably estimated. However, in many cases, investigations are not yet
at a stage where the Company is able to determine whether it is liable or, even
if liability is determined to be probable, to quantify the liability or estimate
a range of possible exposure. In such cases, the amounts of the Company's
liabilities are indeterminate due to the potentially large number of claimants
for any given site or exposure, the unknown magnitude of possible contamination,
the imprecise and conflicting engineering evaluations and estimates of proper
clean-up methods and costs, the unknown timing and extent of the corrective
actions that may be required, the uncertainty attendant to the possible award of
punitive damages, the recent judicial recognition of new causes of action, the
present state of the law, which often imposes joint and several and retroactive
liabilities on PRPs, the fact that the Company is usually just one of a number
of companies identified as a PRP, or other reasons.
As disclosed in note 11, at September 30, 2002, the Company had accrued $242
million for estimated future environmental assessment and remediation costs at
various sites where liabilities for such costs are probable and reasonably
estimable. The Company may also incur additional liabilities in the future at
sites where remediation liabilities are probable but future environmental costs
are not presently reasonably estimable because the sites have not been assessed
or the assessments have not advanced to the stage where costs are reasonably
estimable. At those sites where investigations or feasibility studies have
advanced to the stage of analyzing feasible alternative remedies and/or ranges
of costs, the Company estimates that it could incur possible additional
remediation costs aggregating approximately $245 million. The amount of such
possible additional costs reflects the aggregate of the high ends of the ranges
of costs of feasible alternatives identified by the Company for those sites with
respect to which investigation or feasibility studies have advanced to the stage
of analyzing such alternatives. However, such estimated possible additional
costs are not an estimate of the total remediation costs beyond the amounts
reserved, because there are sites where the Company is not yet in a position to
estimate all, or in some cases any, possible additional costs. Both the amounts
reserved and estimates of possible additional costs may change in the near term,
and in some cases could change substantially, as additional information becomes
available regarding the nature and extent of site contamination, required or
agreed-upon remediation methods and other actions by government agencies and
private parties.
-9-
The accrued costs and the possible additional costs are shown below for four
categories of sites:
At September 30, 2002
----------------------------
Possible
Millions of dollars Reserves Additional
--------------------------------------------------------------------------------
Superfund and similar sites $ 18 $ 11
Active Company facilities 38 63
Company facilities sold with retained liabilities
and former Company-operated sites 90 69
Inactive or closed Company facilities 96 102
--------------------------------------------------------------------------------
Total reserves $ 242 $ 245
================================================================================
The time frames over which the amounts included in the reserves may be paid
extend from the near term to several years into the future. The sites included
in the above categories are in various stages of investigation and remediation;
therefore, the related payments against the existing reserves will be made in
different future periods. Also, some of the work is dependent upon reaching
agreements with regulatory agencies and/or other third parties on the scope of
remediation work to be performed, who will perform the work, the timing of the
work, who will pay for the work and other factors that may have an impact on the
timing of the payments for amounts included in the reserves. For some sites, the
remediation work will be performed by other parties, such as the current owners
of the sites, and the Company has a contractual agreement to pay a share of the
remediation costs. For these sites, the Company generally has less control over
the timing of the work and consequently the timing of the associated payments.
Based on available information, the Company estimates that the majority of the
amounts included in the reserves will be paid within the next three to five
years.
At the sites where the Company has contractual agreements to share remediation
costs with third parties, the reserves reflect the Company's estimated shares of
those costs. In the case of many of the oil and gas sites, remediation cost
sharing is provided for in joint venture agreements that were made with third
parties during the original operation of the sites. In many cases where the
Company sold facilities or a business to a third party, sharing of remediation
costs for those sites may be included in the sales agreements.
Contamination at the sites of the "Superfund and similar sites" category was the
result of the disposal of substances at these sites by one or more PRPs.
Contamination of these sites could be from many sources, of which the Company
may be one. The Company has been notified that it is a PRP at the sites included
in this category. At the sites where the Company has not denied liability, the
Company's contribution to the contaminated waste at these sites was primarily
from operations identified below.
The "Active Company facilities" category includes oil and gas fields and mining
operations. The oil and gas sites are primarily contaminated with crude oil, oil
field waste and other petroleum hydrocarbons. Contamination at the active mining
sites was principally the result of the impact of mined material on the
groundwater and/or surface water at these sites.
The "Company facilities sold with retained liabilities and former
Company-operated sites" and "Inactive or closed Company facilities" categories
include former Company refineries, transportation and distribution facilities
and service stations. The required remediation of these sites is mainly for
petroleum hydrocarbon contamination as the result of leaking tanks or
impoundments that were used in these operations. Also, included in these
categories are former oil and gas fields that the Company no longer operates. In
most cases, these sites are contaminated with crude oil, oil field waste and
other petroleum hydrocarbons. Contamination at other sites in this category was
the result of former industrial chemical and polymers manufacturing and
distribution facilities, agricultural chemical retail businesses and
ferromolybdenum production operations.
-10-
Superfund and similar sites - At September 30, 2002, Unocal had received
notifications from the U.S. Environmental Protection Agency ("EPA") that the
Company may be a PRP at 29 sites and may share certain liabilities at these
sites. Of the total, three sites are under investigation and/or litigation and
the Company's potential liability is not presently determinable and for one site
the Company has denied responsibility. At one site, the Company has made a final
settlement payment and is in the process of completing its involvement in the
site. Of the remaining 24 sites, where the Company has concluded that liability
is probable and to the extent costs can be reasonably estimated, reserves of $12
million have been established for future remediation and settlement costs.
Various state agencies and private parties had identified 22 other similar PRP
sites. Three sites are under investigation and/or litigation and the Company's
potential liability is not presently determinable and for two sites, the Company
has denied responsibility. At three sites the Company's potential liability
appears to be de minimis. At another site, the Company has made final settlement
payments and is in the process of completing its involvement in the site. Where
the Company has concluded that liability is probable and to the extent costs can
be reasonably estimated at the remaining 13 sites, reserves of $6 million have
been established for future remediation and settlement costs.
In addition to the total of $18 million in reserves mentioned above, the Company
has also estimated that additional costs of $11 million are possible for the
"Superfund and similar sites" category.
Included in this category of sites are:
o The McColl site in Fullerton, California
o The Operating Industries site in Monterey Park, California
o The Casmalia Waste site in Casmalia, California
These 51 sites exclude 110 sites where the Company's liability has been settled,
or where the Company has no evidence of liability and there has been no further
indication of liability by government agencies or third parties for at least a
12-month period.
The Company does not consider the number of sites for which it has been named a
PRP as a relevant measure of liability. Although the liability of a PRP is
generally joint and several, the Company is usually just one of numerous
companies designated as a PRP. The Company's ultimate share of the remediation
costs at those sites often is not determinable due to many unknown factors. The
solvency of other responsible parties and disputes regarding responsibilities
may also impact the Company's ultimate costs.
Active Company facilities - The Company has established reserves of $38 million
for estimated future costs of remedial orders, corrective actions and other
investigation, remediation and monitoring obligations at certain operating
facilities and producing oil and gas fields. Included in this category are:
o The Molycorp molybdenum mine in Questa, New Mexico
o The Molycorp lanthanide facility in Mountain Pass, California
o Alaska oil and gas properties
The Company estimates that it may incur possible additional costs of $63 million
for this category of sites.
Company facilities sold with retained liabilities and former Company-operated
sites - Company facilities sold with retained liabilities include:
o West Coast refining, marketing and transportation sites
o Auto/truckstop facilities in various locations in the U.S.
o Industrial chemical and polymer sites in the South, Midwest and California
o Agricultural chemical sites in the West and Midwest.
-11-
In each sale, the Company retained a contractual remediation or indemnification
obligation and is responsible only for certain environmental problems associated
with its past operations. The reserves represent estimated future costs for
remediation work: identified prior to the sale of these sites; included in
negotiated agreements with the buyers of these sites where the Company retained
certain levels of remediation liabilities; and/or identified in subsequent
claims made by buyers of the properties. Former Company-operated sites include
service stations, distribution facilities and oil and gas fields that were
previously operated but not owned by the Company. The Company has established
aggregate reserves of $90 million and additional costs of $69 million are
possible for this category. The possible additional costs are primarily related
to service station and distribution facilities and oil and gas properties.
Inactive or closed Company facilities - Reserves of $96 million have been
established for these types of facilities. The major sites in this category are:
o The Guadalupe oil field on the central California coast
o The Molycorp Washington and York facilities in Pennsylvania
o The Beaumont Refinery in Texas.
The sites in this category also have possible additional costs of $102 million
associated with them.
The Company is subject to federal, state and local environmental laws and
regulations, including the Comprehensive Environmental Response, Compensation
and Liability Act of 1980 ("CERCLA"), as amended, the Resource Conservation and
Recovery Act ("RCRA") and laws governing low level radioactive materials. Under
these laws, the Company is subject to existing and/or possible obligations to
remove or mitigate the environmental effects of the disposal or release of
certain chemical, petroleum and radioactive substances at various sites.
Corrective investigations and actions pursuant to RCRA and other federal, state
and local environmental laws are being performed at the Company's Beaumont,
Texas, facility, a former agricultural chemical facility in Corcoran,
California, and Molycorp's Washington, Pennsylvania, facility. In addition,
Molycorp is required to decommission its Washington and York facilities in
Pennsylvania pursuant to the terms of their respective radioactive source
materials licenses and decommissioning plans.
The Company also must provide financial assurance for future closure and
post-closure costs of its RCRA-permitted facilities and for decommissioning
costs at facilities that are under radioactive source materials licenses.
Pursuant to a 1998 settlement agreement between the Company and the State of
California (and the subsequent stipulated judgment entered by the Superior
Court), the Company must provide financial assurance for anticipated costs of
remediation activities at its inactive Guadalupe oil field. Also, pursuant to a
1995 settlement agreement between Molycorp and the California Department of
Toxic Substances Control (and subsequent final judgment entered by the Superior
Court), the Company must provide financial assurance for anticipated costs of
disposing of certain wastes, as well as closing facilities associated with the
handling of those wastes, at Molycorp's Mountain Pass, California, facility. At
September 30, 2002, amounts included in the remediation reserves for these
facilities totaled $103 million. At those sites where investigations or
feasibility studies have advanced to the stage of analyzing alternative remedies
and/or ranges of costs, the Company estimates that it could incur possible
additional remediation costs aggregating approximately $74 million. Although any
possible additional costs are likely to be incurred at different times and over
a period of many years, the Company believes that these obligations could have a
material adverse effect on the Company's results of operations but are not
expected to be material to the Company's consolidated financial condition or
liquidity.
The total environmental remediation reserves recorded on the consolidated
balance sheet represent the Company's estimates of assessment and remediation
costs based on currently available facts, existing technology and presently
enacted laws and regulations. The remediation cost estimates, in many cases, are
based on plans recommended to the regulatory agencies for approval and are
subject to future revisions. The ultimate costs to be incurred could exceed the
total amounts reserved. The reserve will be adjusted as additional information
becomes available regarding the nature and extent of site contamination,
required or agreed-upon remediation methods and other actions by government
agencies and private parties. Therefore, amounts reserved may change
substantially in the near term.
-12-
The Company maintains insurance coverage intended to reimburse the cost of
damages and remediation related to environmental contamination resulting from
sudden and accidental incidents under current operations. The purchased
coverages contain specified and varying levels of deductibles and payment
limits. Although certain of the Company's contingent legal exposures enumerated
above are uninsurable due either to insurance policy limitations, public policy
or market conditions, management believes that its current insurance program
significantly reduces the possibility of an incident causing a material adverse
financial impact to the Company.
Certain Litigation and Claims
City of Santa Monica MTBE Lawsuit: In September 2000, the City of Santa Monica
(the "City") sued Shell Oil Company and other oil companies, including the
Company, for contamination with methyl tertiary butyl ether ("MTBE") and a
related chemical of water pumped from its Charnock wellfield (City of Santa
Monica v Shell Oil Company et al, California Superior Court, Orange County, Case
No. 01CC04331). In August 2001, Shell filed a cross-complaint against the
Company and other oil companies, seeking the recovery of the funds it has
expended to respond to the contamination. Further proceedings on this
cross-complaint remain stayed.
The City's first amended complaint, filed in May 2002, alleges causes of action
for strict liability (gasoline containing MTBE as a defective product designed,
manufactured and sold without adequate warnings), negligence, trespass, public
and private nuisance, declaratory relief and unfair competition. The City seeks
damages, a declaration that the defendants are liable for all remedial actions,
abatement of nuisance and injunctive relief. The City alleges that releases from
sites of units of Shell, ChevronTexaco Corporation and ExxonMobil Corporation
were the releases which caused the wellfield to be shut down. Releases from
Company sites allegedly impacted the wellfield subsequently. The Company filed
its answer to the City's complaint in August 2002.
In November 2002, the City, ChevronTexaco and ExxonMobil entered into a
settlement, subject to court approval, under which the two companies would pay
the City $30 million and construct and operate a water treatment plant. Future
settlement and/or judgment amounts paid to the City from other defendants would
go in part into an operating account, from which the two companies could be
reimbursed for part or all of their treatment plant costs, as well as certain
other costs. The Company, Tosco Corporation (now a unit of Phillips Petroleum
Company) and other defendants, but not the Shell defendants, have been invited
to participate in this settlement. The Company is evaluating its position with
regard to participation, which would involve its paying the City $7.5 million
and contributing to the costs of the treatment plant. However, based on a
rigorous technical analysis of the data, the Company believes it has strong
defenses to the allegations in the complaint, including the lack of evidence
that its former service stations or activities are responsible for any
contamination that has reached or threatens the wellfield. The Company also
believes it has certain available defenses that the settling defendants and
others may not have due to tolling agreements they entered into with the City;
and, unlike the Shell defendants and the settling defendants, the Company is
neither the object of punitive damages claims nor a cause of the wellfield's
being originally shut down. The Company is also subject to potential partial
responsibility for liabilities arising from its former gasoline marketing
business that was sold in 1997. The Company's current analysis does not
indicate any such liabilities are likely to be significant.
For several years prior to the City's suit, the EPA and the California Regional
Water Quality Control Board have asserted jurisdiction over contamination of
groundwater potentially affecting the wellfield, and these agencies have issued
a number of orders under RCRA and state law to the Shell defendants and the
other defendant oil companies, including the Company, with respect to both
investigation of individual facilities and regional contamination, and requiring
replacement of water lost to the City, which Shell is currently providing. The
impact of the proposed settlement in the City's lawsuit on future government
agency actions is uncertain. The Company has submitted to these agencies several
technical analyses, which it believes demonstrate that its sites are not a part
of any regional contamination problem, but, rather, present, at the most,
localized issues which the Company, under agency oversight, has been
successfully resolving.
-13-
Agrium Litigation: In June 2002, a lawsuit was filed against the Company by
Agrium Inc., a Canadian corporation, and a U. S. subsidiary in the California
Superior Court, Los Angeles County (Agrium U.S. Inc. and Agrium Inc. v. Union
Oil Company of California, Case No. BC275407). The Company subsequently removed
the case to the U.S. District Court for the Central District of California (Case
No. 02-04769 Nm).
The Agrium entities ("Agrium") allege numerous causes of action relating to
their purchase from the Company of a nitrogen-based fertilizer plant on the
Kenai Peninsula, Alaska, in September 2000. The primary allegations involve the
Company's obligation to supply natural gas to the plant pursuant to a Gas
Purchase and Sale Agreement (the "GPSA") between the parties. Agrium alleges
that the Company misrepresented the amount of gas reserves available for sale to
the plant as of the closing of the transaction and that the Company has failed
to develop additional reserves for sale to the plant. Agrium also alleges that
the Company misrepresented the condition of the general effluent sewer at the
plant and made misrepresentations regarding other environmental matters.
Agrium seeks damages in an unspecified amount for breach of such representations
and warranties, as well as for alleged misconduct by the Company in operating
and managing certain oil and gas leases and other facilities. Agrium also seeks
declaratory relief concerning the base price of gas under the GPSA, as well as
for the calculation of payments under a "Retained Earnout" covenant that
entitles the Company to certain contingent payments based on the price of
ammonia subsequent to the September 2000 closing. The complaint includes demands
for punitive damages and attorneys' fees.
Also in June 2002, the Company filed a lawsuit against Agrium in the U.S.
District Court for the Central District of California (Union Oil Company of
California v. Agrium Inc. and Agrium U.S. Inc., Case No. 02-04518 Nm(Ctx)). The
Company seeks declaratory relief in its favor against the allegations of Agrium
set forth above and for judgment on the Retained Earnout in the amount of $16.6
million, together with interest accrued subsequent to May 31, 2002.
The Company believes that certain portions of its disputes with Agrium are
subject to binding arbitration under the terms of the GPSA, and has initiated
arbitration respecting the gas supply available under that agreement. Agrium
claims the dispute resolution provisions of the agreement for the sale of the
plant (the "PSA") supersede the arbitration provisions of the GPSA. Agrium has
filed motions to stay the Company's lawsuit, to enjoin implementation of the
arbitration and for Agrium's lawsuit to be remanded to the state court. A
hearing on these motions is set for December 2002. The federal court denied a
motion by Agrium to temporarily restrain implementation of the arbitration.
The GPSA contains a contractual limit on liquidated damages of $25 million per
year, not to exceed a total of $50 million over the life of the agreement. In
addition, the PSA contains a limit on damages of $50 million. The Company
believes it has a meritorious defense to each of the Agrium claims, but that in
any event its exposure to damages for all disputes is limited by the agreements.
Agrium alleges that it is entitled to recover damages in excess of those
amounts.
In September 2002, Agrium amended its complaint to add allegations that
Unocal breached certain conditions of the September 2000 closing, breached
certain indemnification obligations, and violated the pertinent health and
safety code. Agrium also asked for rescission of the sale of the fertilizer
plant, in addition, or as an alternative, to money damages.
Petrobangla Claim: In July 2002, the Company's subsidiary Unocal Bangladesh
Blocks Thirteen and Fourteen, Ltd. (which was acquired in 1999 from Occidental
Petroleum Corporation and, prior to the recent completion of Bangladesh
name-change formalities, was still known in Bangladesh as Occidental of
Bangladesh Ltd.) ("OBL"), received from the Bangladesh Oil, Gas & Mineral
Corporation ("Petrobangla") a letter claiming, on behalf of the Bangladesh
government and Petrobangla, compensation allegedly due in the amount of $685
million for 246 BCF of recoverable natural gas allegedly "lost and damaged" in a
1997 blowout and ensuing fire during the drilling by OBL, as operator, of the
Moulavi Bazar #1 ("MB #1") exploration well on the Blocks 13 and 14 PSC area in
Northeast Bangladesh. The Company and OBL believe that the claim vastly
overstates the amount of recoverable gas involved in the blowout.
-14-
Consistent with worldwide industry contracting practice, there was no provision
in the PSC for compensating the Bangladesh government or Petrobangla for
resources lost during the contractors' operations. Even if some form of
compensation were due, the Company and OBL believe that settlement compensation
for the blowout was fully addressed in a 1998 Supplemental Agreement to the PSC,
which, among other matters, waived OBL's then 50-percent contractor's share (as
well as the then 50-percent contractor's share held by the Company's Unocal
Bangladesh, Ltd., subsidiary) of entitlement to the recovery of costs incurred
in the blowout, waived their right to invoke force majeure in connection with
the blowout, and reduced by five percentage points their contractors' profit
share (with a concomitant increase in Petrobangla's profit share) of future
production from the sands encountered by the MB #1 well to a drill depth of 840
meters or, if the blowout sand reservoir were not deemed commercial, from other
commercial fields in the Moulavi Bazar "ring-fenced" area of Block 14.
Consequently, the Company and OBL consider the matter closed and OBL has advised
Petrobangla that no additional compensation is warranted.
In view of the inherent difficulty of predicting the outcome of legal matters,
the Company cannot state with confidence what the eventual outcome of the three
preceding matters will be. However, based on current knowledge, none of the
preceding matters is presently expected to have a material adverse effect on the
Company's consolidated financial condition or liquidity, but each of them could
have a material adverse effect on the Company's results of operations for the
accounting period or periods in which one or more of them might be resolved
adversely.
Tax matters
The Company believes it has adequately provided in its accounts for tax items
and issues not yet resolved. Several prior material tax issues are unresolved.
Resolution of these tax issues impact not only the year in which the items
arose, but also the Company's tax situation in other tax years. With respect to
1979-1984 taxable years, all issues raised for these years have now been
settled, with the exception of the effect of the carryback of a 1993 net
operating loss ("NOL") to tax year 1984 and resultant credit adjustments. The
1985-1990 taxable years are before the Appeals division of the Internal Revenue
Service. All issues raised with respect to those years have now been settled,
with the exception of the effect of the 1993 NOL carryback and resultant
adjustments. The Joint Committee on Taxation of the U.S. Congress has reviewed
the settled issues with respect to 1979-1990 taxable years and no additional
issues have been raised. While all tax issues for the 1979-1990 taxable years
have been agreed and reviewed by the Joint Committee, these taxable years will
remain open due to the 1993 NOL carryback. The 1993 NOL results from certain
specified liability losses, which occurred during 1993, and which resulted in a
tax refund of $73 million. Consequently, these tax years will remain open until
the specified liability loss, which gave rise to the 1993 NOL, is finally
determined by the Internal Revenue Service and is either agreed to with the IRS
or otherwise concluded in the Tax Court proceeding. In 1999, the United States
Tax Court granted Unocal's motion to amend the pleadings in its Tax Court cases
to place the 1993 NOL carryback in issue. The 1991-1994 taxable years are now
before the Appeals division of the Internal Revenue Service. The 1995-1997
taxable years are under examination by the Internal Revenue Service.
Pure Resources, Inc. Employment and Severance Agreements
Under circumstances specified in the employment and/or severance agreements
entered into between the Company's Pure subsidiary and its officers, each
covered officer will have the right to require Pure to purchase its common
shares currently held or subsequently obtained by the exercise of any option
held by the officer at a calculated "net asset value" per share. The
circumstances under which certain officers may exercise this right include the
termination of the officer without cause prior to May 25, 2003, termination for
any reason after May 24, 2003, a change in control of either Pure or Unocal and
other events specified in the agreements. The net asset value per share is
calculated by reference to each common share's pro rata amount of the present
value of Pure's proved reserves discounted at 10 percent, as defined, times 110
percent, less funded debt, as defined. At September 30, 2002, Pure estimated
that the amount it may have to repurchase under these agreements was
approximately $111 million, which is reflected as subsidiary stock subject to
repurchase on the consolidated balance sheet. The repurchase amount will
fluctuate with changes in the net asset value per share. At December 31, 2001,
the repurchase amount under these agreements was approximately $70 million. See
note 16 for details on the Company's acquisition of the remaining shares of Pure
which it did not already own, that eliminated the obligation for stock subject
to repurchase.
-15-
Other matters
The Company has a lease agreement relating to its Discoverer Spirit deepwater
drillship, with a remaining term of approximately three years at September 30,
2002. In 2001, the Company signed a sublease agreement with a third party for a
period that began in December 2001 and ended in the middle of September 2002.
Under the provisions of that agreement, the third party assumed all of the lease
payments to the lessor during the sublease period. The drillship has a minimum
daily rate of approximately $219,000. The future remaining minimum lease payment
obligation was approximately $240 million at September 30, 2002.
In the normal course of business, the Company has performance obligations which
are secured, in whole or in part, by surety bonds or letters of credit. These
obligations primarily cover self-insurance, site restoration, dismantlement and
other programs where governmental organizations require such support. These
surety bonds and letters of credit are issued by financial institutions but are
funded by the Company if exercised. At September 30, 2002, the Company,
including its Pure subsidiary, had obtained various surety bonds for
approximately $225 million. These surety bonds included a bond for $96 million
securing the Company's performance under a fixed price natural gas sales
contract for the delivery of 72 billion cubic feet of gas over a ten-year period
that began in January of 1999 and will end in December of 2008 and approximately
$100 million in various other routine performance bonds held by local, city,
state and federal agencies. The Company also had obtained approximately $40
million in standby letters of credit at September 30, 2002. The Company has
entered into indemnification obligations in favor of the providers of these
surety bonds and letters of credit. In addition, the Company has various other
guarantees for approximately $545 million. Guarantees for approximately $332
million of this amount would require the Company to obtain a surety bond or a
letter of credit or establish a trust fund if its credit rating were to drop
below investment grade--that is BBB- or Baa3 from Standard & Poor's Ratings
Services and Moody's Investors Service, Inc., respectively. Approximately $180
million of the surety bonds, letters of credit and other guarantees that the
Company is required to obtain or issue reflect obligations that are already
included on the consolidated balance sheet in other current liabilities and
other deferred credits. The surety bonds, letters of credit and other guarantees
may also reflect some of the possible additional remediation liabilities
discussed earlier in this note.
Approximately $134 million of the $545 million in guarantees mentioned in the
previous paragraph represents financial assurance given by the Company on behalf
of its Molycorp subsidiary relating to permits covering discharges from its
Questa, New Mexico, molybdenum mine. The Company's financial assurance is for
the completion of temporary closure plans (required only upon cessation of
operations) and other obligations required under the terms of the permits. The
costs associated with the financial assurance are based on estimations provided
by agencies of the state of New Mexico.
The Company has certain investments in entities that it accounts for under the
equity method, such as Colonial Pipeline Company. These entities have
approximately $1.7 billion of their own debt obligations that are either fully
non-recourse or of limited recourse to the Company. Of the total $1.7 billion in
equity investee debt, $1.1 billion belongs to the Colonial Pipeline Company, in
which the Company holds a 23.44 percent equity interest. The Company guarantees
only $25 million of the total $1.7 billion debt obligations.
The Company also has other contingent liabilities with respect to litigation,
claims and contractual agreements arising in the ordinary course of business. On
the basis of management's assessment of the ultimate amount and timing of
possible adverse outcomes and associated costs, none of such matters is
presently expected to have a material adverse effect on the Company's
consolidated financial condition, liquidity or results of operations.
-16-
13. Financial Instruments and Commodity Hedging
Fair values of debt and other long-term instruments - The estimated fair value
of the Company's long-term debt at September 30, 2002, including the current
portion, was approximately $3.45 billion. The fair value was based on the
discounted amounts of future cash outflows using the rates offered to the
Company for debt with similar remaining maturities.
The estimated fair value of the mandatorily redeemable convertible preferred
securities of the Company's subsidiary trust was approximately $515 million at
September 30, 2002. The fair value was based on the closing trading price of the
preferred securities on September 30, 2002.
Commodity hedging activities - During the nine months ended September 30, 2002,
the Company recognized $1 million in after-tax losses for the ineffectiveness of
both cash flow and fair value hedges. For the third quarter of 2002, the
earnings impact of ineffectiveness was immaterial. At September 30, 2002, the
Company had approximately $11 million of after-tax deferred losses in
accumulated other comprehensive income on the consolidated balance sheet related
to cash flow hedges for future commodity sales for the period beginning October
2002 through October 2004. Of this amount, approximately $5 million in after-tax
losses are expected to be reclassified to the consolidated earnings statement
during the next twelve months.
Foreign currency contracts - At September 30, 2002, the Company had
approximately $1 million of after-tax deferred gains in accumulated other
comprehensive income on the consolidated balance sheet related to cash flow
hedges for future foreign currency denominated payment obligations through
December 2003. Nearly all of this amount is expected to be reclassified to the
consolidated earnings statement during the next twelve months.
Interest rate contracts - At September 30, 2002, the Company had approximately
$25 million of after-tax deferred losses in accumulated other comprehensive
income on the consolidated balance sheet related to cash flow hedges of interest
rate exposures through September 2012. Of this amount, $3 million in after-tax
losses are expected to be reclassified to the consolidated earnings statement
during the next twelve months.
Credit Risk - The Company has taken appropriate action to help mitigate credit
exposure to counterparties whose creditworthiness has deteriorated since the
beginning of the year. Counterparty credit lines have been reduced substantially
or rescinded entirely where it has been determined that there is unwarranted
credit exposure. In other instances, credit assurances in the form of
prepayments, letters of credit or guarantees have been obtained to support the
credit extension.
-17-
14. Supplemental Condensed Consolidating Financial Information
Unocal guarantees all the publicly held securities issued by its 100
percent-owned subsidiaries Unocal Capital Trust and Union Oil. Such guarantees
are full and unconditional and no subsidiaries of Unocal or Union Oil guarantee
these securities.
The following tables present condensed consolidating financial information for
(a) Unocal (Parent), (b) the Trust, (c) Union Oil (Parent) and (d) on a combined
basis, the subsidiaries of Union Oil (non-guarantor subsidiaries). Virtually all
of the Company's operations are conducted by Union Oil and its subsidiaries.
CONDENSED CONSOLIDATING EARNINGS STATEMENT
For the three months ended September 30, 2002
Unocal Non-
Unocal CapitalUnion Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 310 $ 1,187 $ (210) $ 1,287
Interest, dividends and miscellaneous income 1 8 (68) 65 (9) (3)
Gain (loss) on sales of assets - - 1 - - 1
-------------------------------------------------------------------------------------------------------------
Total revenues 1 8 243 1,252 (219) 1,285
Costs and other deductions
Purchases, operating and other expenses 1 - (52) 1,077 (210) 816
Depreciation, depletion and amortization - - 81 164 - 245
Impairments - - 2 4 - 6
Dry hole costs - - 5 35 - 40
Interest expense 8 - 31 9 (8) 40
Distributions on convertible preferred securities - 8 - - - 8
-------------------------------------------------------------------------------------------------------------
Total costs and other deductions 9 8 67 1,289 (218) 1,155
Equity in earnings of subsidiaries 101 - (13) - (88) -
Earnings from equity investments - - 1 34 - 35
-------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 93 - 164 (3) (89) 165
-------------------------------------------------------------------------------------------------------------
Income taxes (3) - 63 8 - 68
Minority interests - - - 2 (4) (2)
-------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 96 - 101 (13) (85) 99
Earnings from discontinued operations - - - - - -
-------------------------------------------------------------------------------------------------------------
Net earnings $ 96 $ - $ 101 $ (13) $ (85) $ 99
=============================================================================================================
-18-
CONDENSED CONSOLIDATING EARNINGS STATEMENT
For the three months ended September 30, 2001
Unocal Non-
Unocal CapitalUnion Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 360 $ 1,479 $ (266) $ 1,573
Interest, dividends and miscellaneous income 1 8 - 8 (9) 8
Gain on sales of assets - - (3) 1 - (2)
-------------------------------------------------------------------------------------------------------------
Total revenues - 8 357 1,488 (275) 1,579
Costs and other deductions
Purchases, operating and other expenses 1 - 265 1,080 (272) 1,074
Depreciation, depletion and amortization - - 90 156 - 246
Dry hole costs - - 15 38 - 53
Interest expense 8 - 39 10 (9) 48
Distributions on convertible preferred securities - 8 - - - 8
-------------------------------------------------------------------------------------------------------------
Total costs and other deductions 10 8 409 1,284 (281) 1,429
Equity in earnings of subsidiaries 107 - 147 - (254) -
Earnings from equity investments - - 2 35 - 37
-------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 99 - 97 239 (248) 187
-------------------------------------------------------------------------------------------------------------
Income taxes (3) - (10) 90 - 77
Minority interests - - - 2 6 8
-------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 102 - 107 147 (254) 102
Earnings from discontinued operations - - - - - -
Cumulative effect of accounting change - - - - - -
-------------------------------------------------------------------------------------------------------------
Net earnings $ 102 $ - $ 107 $ 147 $ (254) $ 102
=============================================================================================================
-19-
CONDENSED CONSOLIDATING EARNINGS STATEMENT
For the nine months ended September 30, 2002
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 805 $ 3,466 $ (611) $ 3,660
Interest, dividends and miscellaneous income 1 25 (61) 80 (28) 17
Gain (loss) on sales of assets - - 15 (13) - 2
------------------------------------------------------------------------------------------------------------------------
Total revenues 1 25 759 3,533 (639) 3,679
Costs and other deductions
Purchases, operating and other expenses 4 - 434 2,547 (612) 2,373
Depreciation, depletion and amortization - - 261 463 - 724
Impairments - - 23 4 - 27
Dry hole costs - - 22 59 - 81
Interest expense 25 1 109 27 (28) 134
Distributions on convertible preferred securities - 24 - - - 24
------------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 29 25 849 3,100 (640) 3,363
Equity in earnings of subsidiaries 249 - 313 - (562) -
Earnings from equity investments - - 3 120 - 123
------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 221 - 226 553 (561) 439
------------------------------------------------------------------------------------------------------------------------
Income taxes (10) - (23) 236 - 203
Minority interests - - - 5 (3) 2
------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 231 - 249 312 (558) 234
Earnings from discontinued operations - - - 1 - 1
Cumulative effect of accounting change - - - - - -
------------------------------------------------------------------------------------------------------------------------
Net earnings $ 231 $ - $ 249 $ 313 $ (558) $ 235
========================================================================================================================
-20-
CONDENSED CONSOLIDATING EARNINGS STATEMENT
For the nine months ended September 30, 2001
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 1,540 $ 5,165 $ (1,242) $ 5,463
Interest, dividends and miscellaneous income 6 25 3 21 (28) 27
Gain on sales of assets - - (2) 1 - (1)
------------------------------------------------------------------------------------------------------------------------
Total revenues 6 25 1,541 5,187 (1,270) 5,489
Costs and other deductions
Purchases, operating and other expenses 3 - 932 3,814 (1,269) 3,480
Depreciation, depletion and amortization - - 267 447 - 714
Impairments - - - - - -
Dry hole costs - - 49 91 - 140
Interest expense 25 1 124 23 (28) 145
Distributions on convertible preferred securities - 24 - - - 24
------------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 28 25 1,372 4,375 (1,297) 4,503
Equity in earnings of subsidiaries 658 - 560 - (1,218) -
Earnings from equity investments - - 10 118 - 128
------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 636 - 739 930 (1,191) 1,114
------------------------------------------------------------------------------------------------------------------------
Income taxes (8) - 96 359 - 447
Minority interests - - - 11 27 38
------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 644 - 643 560 (1,218) 629
Earnings from discontinued operations - - 16 - - 16
Cumulative effect of accounting change - - (1) - - (1)
------------------------------------------------------------------------------------------------------------------------
Net earnings $ 644 $ - $ 658 $ 560 $ (1,218) $ 644
========================================================================================================================
-21-
CONDENSED CONSOLIDATING BALANCE SHEET
At September 30, 2002
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ - $ - $ 110 $ 165 $ - $ 275
Accounts and notes receivable - net 51 - 148 556 (65) 690
Inventories - - 13 90 - 103
Other current assets - - 86 31 - 117
-----------------------------------------------------------------------------------------------------------------------------
Total current assets 51 - 357 842 (65) 1,185
Investments and long-term receivables - net 4,119 - 4,579 906 (8,055) 1,549
Properties - net - - 2,179 5,605 - 7,784
Other assets 3 541 152 2,094 (2,508) 282
-----------------------------------------------------------------------------------------------------------------------------
Total assets $4,173 $ 541 $ 7,267 $ 9,447 $ (10,628) $ 10,800
============================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ - $ 235 $ 689 $ (51) $ 873
Current portion of long-term debt and capital leases - - - 8 - 8
Other current liabilities 44 3 169 324 37 577
-----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 44 3 404 1,021 (14) 1,458
Long-term debt and capital leases - - 2,466 604 - 3,070
Deferred income taxes - - (18) 749 - 731
Accrued abandonment, restoration
and environmental liabilities - - 294 301 - 595
Other deferred credits and liabilities 541 - 375 2,352 (2,562) 706
Subsidiary stock subject to repurchase - - - 111 - 111
Minority interests - - - 312 113 425
Company-obligated mandatorily redeemable
convertible preferred securities of a
subsidiary trust holding solely parent debentures - 522 - - - 522
Stockholders' equity 3,588 16 3,746 3,997 (8,165) 3,182
-----------------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $4,173 $ 541 $ 7,267 $ 9,447 $ (10,628) $ 10,800
=============================================================================================================================
-22-
CONDENSED CONSOLIDATING BALANCE SHEET
At December 31, 2001
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ - $ - $ 62 $ 128 $ - $ 190
Accounts and notes receivable - net 51 - 154 693 (51) 847
Inventories - - 3 99 - 102
Other current assets - - 122 34 - 156
-----------------------------------------------------------------------------------------------------------------------------
Total current assets 51 - 341 954 (51) 1,295
Investments and long-term receivables - net 4,032 - 4,143 968 (7,738) 1,405
Properties - net - - 2,149 5,365 - 7,514
Other assets 3 541 214 2,403 (2,950) 211
-----------------------------------------------------------------------------------------------------------------------------
Total assets $4,086 $ 541 $ 6,847 $ 9,690 $ (10,739) $ 10,425
=============================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ - $ 278 $ 596 $ (51) $ 823
Current portion of long-term debt and capital leases - - - 9 - 9
Other current liabilities 42 3 145 400 - 590
-----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 42 3 423 1,005 (51) 1,422
Long-term debt and capital leases - - 2,181 716 - 2,897
Deferred income taxes - - (71) 698 - 627
Accrued abandonment, restoration
and environmental liabilities - - 293 297 - 590
Other deferred credits and liabilities 541 - 312 2,821 (2,950) 724
Subsidiary stock subject to repurchase - - - 70 - 70
Minority interests - - - 309 140 449
Company-obligated mandatorily redeemable
convertible preferred securities of a
subsidiary trust holding solely parent debentures - 522 - - - 522
Stockholders' equity 3,503 16 3,709 3,774 (7,878) 3,124
-----------------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $4,086 $ 541 $ 6,847 $ 9,690 $ (10,739) $ 10,425
=============================================================================================================================
-23-
CONDENSED CONSOLIDATING CASH FLOWS
For the nine months ended September 30, 2002
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities $128 $ - $ 43 $1,061 $ - $1,232
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - - (303) (945) - (1,248)
Proceeds from sales of assets
and discontinued operations - - 23 41 - 64
-------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - - (280) (904) - (1,184)
-------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt and capital leases - - 284 (114) - 170
Dividends paid on common stock (147) - - - - (147)
Minority interests - - - ( 6) - ( 6)
Other 19 - 1 - - 20
-------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (128) - 285 (120) - 37
-------------------------------------------------------------------------------------------------------------------------
Net increase in cash and cash equivalents - - 48 37 - 85
-------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period - - 62 128 - 190
-------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ - $ - $110 $165 $ - $ 275
=========================================================================================================================
CONDENSED CONSOLIDATING CASH FLOWS
For the nine months ended September 30, 2001
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities $132 $ - $ 694 $ 954 $ - $1,780
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - - (526) (1,267) - (1,793)
Proceeds from sales of assets
and discontinued operations - - 47 4 - 51
-------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - - (479) (1,263) - (1,742)
-------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt and capital leases - - (105) 351 - 246
Dividends paid on common stock (146) - - - - (146)
Minority interests - - - ( 17) - ( 17)
Other 14 - 1 - - 15
-------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (132) - (104) 334 - 98
-------------------------------------------------------------------------------------------------------------------------
Net increase in cash and cash equivalents - - 111 25 - 136
-------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period 1 - 84 150 - 235
-------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 1 $ - $195 $175 $ - $ 371
=========================================================================================================================
-24-
15. Segment Data
The Company's reportable segments are: Exploration and Production, Trade,
Midstream, and Geothermal and Power Operations. General corporate overhead,
unallocated costs and other miscellaneous operations, including real estate,
carbon and minerals and activities relating to businesses that were sold, are
included under the Corporate and Other heading.
------------------------------------------------------------------------
Segment Information Exploration & Production Trade
For the Three Months North America International
ended September 30, 2002
Millions of dollars Lower 48 Alaska Canada Far East Other
------------------------------------------------------------------------
Sales & operating revenues $ 120 $ 64 $ 43 $ 271 $ 39 $ 623
Other income (loss) (a) 2 - (1) - 1 (1)
Inter-segment revenues 210 - - 59 37 -
------------------------------------------------------------------------
Total 332 64 42 330 77 622
Earnings (loss) from equity investments - - - 9 2 1
Earnings (loss) from continuing operations 13 10 (2) 129 7 (1)
Earnings from discontinued operations - - - - - -
------------------------------------------------------------------------
Net earnings (loss) 13 10 (2) 129 7 (1)
Assets (at September 30, 2002) 3,228 336 1,088 2,723 834 187
------------------------------------------------------------------------
------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power Admin Net Environ-
Operations & Interest mental &
General Expense Litigation Other (b)
------------------------------------------------------------------------------------
Sales & operating revenues $ 58 $ 28 $ - $ - $ - $ 41 $ 1,287
Other income (loss) (a) 1 (8) - 3 - 1 (2)
Inter-segment revenues 3 - - - - (309) -
------------------------------------------------------------------------------------
Total 62 20 - 3 - (267) 1,285
Earnings (loss) from equity investments 15 (3) - - - 11 35
Earnings (loss) from continuing operations 17 5 (21) (28) (14) (16) 99
Earnings from discontinued operations - - - - - - -
------------------------------------------------------------------------------------
Net earnings (loss) 17 5 (21) (28) (14) (16) 99
Assets (at September 30, 2002) 504 517 - - - 1,383 10,800
------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Includes eliminations and consolidation adjustments.
-25-
------------------------------------------------------------------------
Segment Information Exploration & Production Trade
For the Three Months North America International
ended September 30, 2001
Millions of dollars Lower 48 Alaska Canada Far East Other
------------------------------------------------------------------------
Sales & operating revenues $ 158 $ 86 $ 59 $ 254 $ 35 $ 861
Other income (loss) (a) - - (2) (3) 7 -
Inter-segment revenues 265 - - 45 23 -
-----------------------------------------------------------------------
Total 423 86 57 296 65 861
Earnings (loss) from equity investments (2) - - 10 2 -
Earnings from continuing operations 51 17 6 109 2 3
-----------------------------------------------------------------------
Net earnings 51 17 6 109 2 3
Assets (at December 31, 2001) 3,345 344 1,015 2,463 741 156
-----------------------------------------------------------------------
------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power Admin Net Environ-
Operations & Interest mental &
General Expense Litigation Other (b)
------------------------------------------------------------------------------------
Sales & operating revenues $ 48 $ 46 $ - $ - $ - $ 26 $ 1,573
Other income (loss) (a) - 6 - 6 - (8) 6
Inter-segment revenues 2 - - - - (335) -
-----------------------------------------------------------------------------------
Total 50 52 - 6 - (317) 1,579
Earnings (loss) from equity investments 17 (2) - - - 12 37
Earnings (loss) from continuing operations 13 2 (19) (31) (28) (23) 102
-----------------------------------------------------------------------------------
Net earnings (loss) 13 2 (19) (31) (28) (23) 102
Assets (at December 31, 2001) 479 594 - - - 1,288 10,425
-----------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Includes eliminations and consolidation adjustments.
-26-
-----------------------------------------------------------------------
Segment Information Exploration & Production Trade
For the Nine Months North America International
ended September 30 2002
Millions of dollars Lower 48 Alaska Canada Far East Other
-----------------------------------------------------------------------
Sales & operating revenues $ 357 $ 188 $ 143 $ 765 $ 99 $ 1,723
Other income (loss) (a) 6 - (1) - 1 (1)
Inter-segment revenues 610 - - 173 78 1
-----------------------------------------------------------------------
Total 973 188 142 938 178 1,723
Earnings (loss) from equity investments - - - 26 6 1
Earnings (loss) from continuing operations 37 (1) (5) 332 31 1
Earnings from discontinued operations - - - - - -
-----------------------------------------------------------------------
Net earnings (loss) 37 (1) (5) 332 31 1
Assets (at September 30, 2002) 3,228 336 1,088 2,723 834 187
-----------------------------------------------------------------------
------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power Admin Net Environ-
Operations & Interest mental &
General Expense Litigation Other (b)
------------------------------------------------------------------------------------
Sales & operating revenues $ 197 $ 89 $ - $ - $ - $ 99 $ 3,660
Other income (loss) (a) 3 (4) - 11 - 4 19
Inter-segment revenues 9 - - - - (871) -
------------------------------------------------------------------------------------
Total 209 85 - 11 - (768) 3,679
Earnings (loss) from equity investments 52 (1) - - - 39 123
Earnings (loss) from continuing operations 59 25 (64) (93) (50) (38) 234
Earnings from discontinued operations - - - - - 1 1
------------------------------------------------------------------------------------
Net earnings (loss) 59 25 (64) (93) (50) (37) 235
Assets (at September 30, 2002) 504 517 - - - 1,383 10,800
------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Includes eliminations and consolidation adjustments.
-27-
-----------------------------------------------------------------------
Segment Information Exploration & Production
For the Nine Months North America International Trade
ended September 30, 2001
Millions of dollars Lower 48 Alaska Canada Far East Other
-----------------------------------------------------------------------
Sales & operating revenues $ 486 $ 221 $ 188 $ 755 $ 109 $ 3,289
Other income (loss) (a) 1 - (1) (9) 6 (1)
Inter-segment revenues 1,237 - - 155 84 1
-----------------------------------------------------------------------
Total 1,724 221 187 901 199 3,289
Earnings from equity investments 12 - - 29 2 -
Earnings from continuing operations 434 49 17 328 29 10
Earnings from discontinued operations - - - - - -
Cumulative effect of accounting change - - - - - -
-----------------------------------------------------------------------
Net earnings 434 49 17 328 29 10
Assets (at December 31, 2001) 3,345 344 1,015 2,463 741 156
-----------------------------------------------------------------------
------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power Admin Net Environ-
Operations & Interest mental &
General Expense Litigation Other (b)
------------------------------------------------------------------------------------
Sales & operating revenues $ 187 $ 135 $ - $ - $ - $ 93 $ 5,463
Other income (loss) (a) 2 13 - 19 - (4) 26
Inter-segment revenues 6 - - - - (1,483) -
-----------------------------------------------------------------------------------
Total 195 148 - 19 - (1,394) 5,489
Earnings (loss) from equity investments 45 (2) - - - 42 128
Earnings (loss) from continuing operations 40 5 (63) (96) (78) (46) 629
Earnings from discontinued operations - - - - - 16 16
Cumulative effect of accounting change - - - - - (1) (1)
-----------------------------------------------------------------------------------
Net earnings (loss) 40 5 (63) (96) (78) (31) 644
Assets (at December 31, 2001) 479 594 - - - 1,288 10,425
-----------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Includes eliminations and consolidation adjustments.
16. Subsequent Event
On October 29, 2002, the Company completed its exchange offer for the remaining
shares of Pure Resources, Inc. ("Pure"), that it did not already own. In the
exchange offer, the Company exchanged 0.74 shares of Unocal common stock for
each share of Pure common stock it did not already own. The Company accepted
tenders of 16,634,625 Pure shares in the exchange offer, which when combined
with the 65 percent of the shares it already owned, represented approximately
97.5 percent of Pure's outstanding common shares. On October 30, 2002, the
Company completed a short-form merger to acquire the remaining 2.5 percent of
Pure's outstanding shares at the same 0.74 exchange ratio used in the exchange
offer. Consequently, Pure is now a wholly owned subsidiary of the Company. This
transaction was valued at approximately $390 million and eliminated the
minority interest liability relating to Pure and all of the outstanding balance
under the caption "Subsidiary stock subject to repurchase" on the Company's
consolidated balance sheet. See note 12 for additional information on the "Pure
Severance and Employment Agreements". The transaction will be reflected in the
Company's fourth quarter results.
-28-
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
The following discussion and analysis of the consolidated financial condition
and results of operations of the Company should be read in conjunction with
Management's Discussion and Analysis in Item 7 of Unocal's amended 2001 Annual
Report on Form 10-K/A.
CONSOLIDATED RESULTS
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
------------------------------------------
Millions of dollars 2002 2001 2002 2001
--------------------------------------------------------------------------------
Earnings from continuing operations $ 99 $ 102 $ 234 $ 629
Earnings from discontinued operations - - 1 16
Cumulative effect of accounting change - - - (1)
--------------------------------------------------------------------------------
Net earnings $ 99 $ 102 $ 235 $ 644
================================================================================
Continuing Operations
Third Quarter Results: Earnings from continuing operations were $99 million, or
41 cents per share (diluted), in the third quarter of 2002, compared with $102
million, or 42 cents per share (diluted), for the same period a year ago. The
decrease was primarily due to lower natural gas production compared with the
same period a year ago, principally in the Lower 48 operations, which reflected
lower Gulf of Mexico natural gas production primarily from a decline in
Ship Shoal Block 295 ("Muni field") production (7 MMcf/d, net of royalty, in the
third quarter of 2002 versus 140 MMcf/d, net of royalty, in the third quarter of
2001), the effect of reduced second-half 2001 drilling activity compared with
the first half of 2001, and storm-related production curtailments in the Gulf of
Mexico. The lower production in the Lower 48 operations was partially offset by
higher natural gas production from International operations. Worldwide net daily
production in the third quarter of 2002 averaged 466,000 barrels-of-oil
equivalent ("BOE") per day compared with 506,000 BOE per day a year ago. The
lower worldwide production reduced net earnings by approximately $30 million.
The third quarter of 2002 also included an after-tax loss of $5 million in
mark-to-market accruals and realized gains/losses for non-hedge commodity
derivatives recorded by the Company's Northrock Resources Ltd. ("Northrock")
subsidiary, compared with an after-tax gain of $1 million in the same period a
year ago.
Higher liquids prices partially offset the decline in net earnings by
approximately $10 million. In the third quarter of 2002, the Company's worldwide
average liquids price was $24.19 per barrel, which was an increase of $1.32 per
barrel, or 6 percent, from the same period a year ago. The Company's hedging
activity lowered the average liquids price by one cent per barrel in the third
quarter of 2002 while the third quarter of 2001 included a gain of one cent per
barrel from hedging activities. Dry hole costs and exploration expense were $15
million lower, primarily in International operations, in the third quarter of
2002 compared to the same period a year ago. In addition, improved margins from
Midstream operations coupled with improved carbon and mineral results (which are
included in the Corporate and Other results) increased net earnings by
approximately $10 million in the third quarter of 2002 compared to the same
period a year ago. After-tax provisions for environmental and litigation matters
were $22 million in the third quarter of 2002, compared with $26 million in the
same period a year ago.
Nine Months Results: Earnings from continuing operations were $234 million, or
96 cents per share (diluted), in the nine months period of 2002, compared with
$629 million, or $2.53 per share (diluted), for the same period a year ago. The
decrease was primarily due to lower commodity prices and lower worldwide
production. Lower natural gas prices reduced net earnings by approximately $190
million, while lower liquids prices reduced net earnings by approximately $50
million. The Company's worldwide average natural gas price, including a benefit
of 4 cents per Mcf from hedging activities, was $2.65 per Mcf for the nine
months period of 2002, which was a decrease of 86 cents per Mcf or 25 percent
from the $3.51 per Mcf, including a loss of six cents per Mcf from hedging
activities, in the same period a year ago. In the nine months period of 2002,
the Company's worldwide average liquids price was $21.77 per barrel, including a
benefit of one cent per barrel from hedging activities, which was a decrease of
$2.12 per barrel, or 9 percent, from the $23.89 per barrel price, including a
loss of 3 cents per barrel from hedging activities, from the same period a year
ago.
-29-
The results in the nine months period of 2002 were impacted by lower natural gas
production compared with the same period a year ago, which reduced net earnings,
by approximately $165 million. Worldwide, net daily production in the nine
months period of 2002 averaged 476,000 BOE per day, compared with 506,000 BOE
per day a year ago. The lower production was principally in the Lower 48
operations, which reflected lower Gulf of Mexico natural gas production stemming
from the decline in Muni field production (11 MMcf/d, net of royalty, in the
nine months period of 2002 versus 107 MMcf/d, net of royalty, for the same
period a year ago) and the reduction in the second-half 2001 drilling activity.
The lower production in the Lower 48 operations was partially offset by higher
production from International operations.
The results in the nine months period of 2002 included $18 million in higher
pension related expenses. The nine months of 2002 included $9 million after-tax
in pension related expenses, compared to income of $9 million after-tax in the
nine months period of 2001. The results in the nine months period of 2002
included a $12 million after-tax impairment of certain properties in Alaska and
a $12 million after-tax restructuring provision for the Gulf Region business
unit. The nine months period of 2002 included an after-tax loss of $5 million in
mark-to-market accruals and realized gains/losses for non-hedge commodity
derivatives by Northrock, compared with an after-tax gain of $5 million in the
same period a year ago.
These negative results in the nine months period of 2002 were partially offset
by $40 million in lower dry hole costs compared with the same period a year ago.
In addition, after-tax provisions for environmental and litigation matters were
$56 million in the nine months period of 2002, compared with $71 million in the
same period a year ago. The nine months period results of 2002 also included a
$2 million after-tax gain from an insurance settlement reached with insurers for
the recovery of amounts previously paid out by the Company for environmental
pollution claims and related costs, as well as a $2 million after-tax gain
adjustment related to a Lower 48 prior year asset sale.
Discontinued Operations
The nine months period of 2002 included a $1 million after-tax gain from
discontinued operations, related to a participation payment received from the
purchaser of the Company's former West Coast refining, marketing and
transportation assets covering price differences between California Air
Resources Board Phase 2 gasoline and conventional gasoline. The total after-tax
gain in the comparable period of 2001 was $16 million, or 6 cents per share
(diluted).
Cumulative Effect of Accounting Change
In the first quarter of 2001, the Company recorded a one-time non-cash $1
million after-tax charge consisting of the cumulative effect of a change in
accounting principle related to the initial adoption of Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities".
Revenues
Total revenues from continuing operations for the third quarter of 2002 were
$1.29 billion, compared with $1.58 billion for the same period a year ago. The
decrease in the third quarter revenues primarily reflected lower U.S. domestic
natural gas and liquids production and reduced marketing activity related to the
Company's domestic equity production of crude oil. For the nine months period of
2002, total revenues from continuing operations were $3.68 billion, compared
with $5.49 billion for the same period a year ago. The decrease in the nine
months results primarily reflected lower average hydrocarbon commodity prices,
lower domestic natural gas production and reduced marketing activity related to
the Company's domestic equity crude production.
-30-
Exploration and Production
The Company engages in oil and gas exploration, development and production
worldwide. The results of this segment are discussed under two geographical
breakdowns: North America and International.
North America - Included in this category are the U.S. Lower 48, Alaska and
Canada oil and gas operations. The emphasis of the U.S. Lower 48 operations is
on the onshore, shelf and deepwater areas of the Gulf of Mexico region. The U.S.
Lower 48 also includes the consolidated results of Pure Resources, Inc.
("Pure"), which operates primarily in the Permian and San Juan Basins in west
Texas and New Mexico, the Gulf of Mexico region and offshore in the Gulf of
Mexico. A substantial portion of the crude oil and natural gas produced in the
U.S. Lower 48 operations, excluding that of Pure, is sold to the Company's Trade
business segment. The remainder of North America production, including that of
Pure and of Northrock in Canada, is sold to third parties. In Alaska, natural
gas production, pursuant to agreements with the purchaser of the Company's
former agricultural products business, is sold to a fertilizer plant in Nikiski,
Alaska. In addition, the Company, including Pure, uses hydrocarbon derivative
financial instruments such as futures, swaps and options to hedge portions of
the Company's exposure to commodity price fluctuations.
Third Quarter Results: After-tax earnings were $21 million in the third quarter
of 2002 compared to $74 million for the same period a year ago, which was a
decrease of $53 million. The decrease was primarily due to lower natural gas and
liquids production. Lower natural gas production during the third quarter of
2002 compared to the same period a year ago reduced after-tax earnings by
approximately $40 million. North America average net daily natural gas
production was 867 MMcf/d in the third quarter of 2002 compared to 1,114 MMcf/d
in the same period a year ago, which was a decrease of 22 percent. Natural gas
production in the Lower 48 averaged 716 MMcf/d in the third quarter of 2002
compared to 939 MMcf/d in the same period a year ago. This decline reflected
lower natural gas production from the Gulf of Mexico shelf area including
production from the Muni field, which averaged 7 MMcf/d, net of royalty, in the
third quarter of 2002 compared to 140 MMcf/d, net of royalty, during the third
quarter of 2001. In addition, reduced second-half 2001 drilling activity
compared with the first half of 2001 and storm-related production curtailments
in the Gulf of Mexico contributed to the production decline. Lower liquids
production during the third quarter of 2002 compared to the same period a year
ago reduced after-tax earnings by $10 million. North America average net daily
liquids production was 92 MBbl/d in the third quarter of 2002 compared to 102
MBbl/d in the same period a year ago, which was a decrease of 10 percent. In
addition to lower production, Northrock recorded $5 million in after-tax losses
related to mark-to-market accruals and realized gains and losses for non-hedging
commodity derivative positions during the third quarter of 2002 compared to an
after-tax gain of $1 million in the same period a year ago.
Nine Months Results: After-tax earnings were $31 million in the nine months
period of 2002 compared to $500 million for the same period a year ago, which
was a decrease of $469 million. The decrease was primarily due to lower natural
gas and liquids prices and lower natural gas production. The average natural gas
price for North America, including a gain of 8 cents per Mcf from hedging
activities, was $2.69 per Mcf in the nine months period of 2002 compared to
$4.29 per Mcf in the same period a year ago, which included a loss of 11 cents
per Mcf from hedging activities. In the nine months period of 2002, the
Company's North America average liquids price, including a gain of 2 cents per
Bbl from hedging activities, was $21.14 per Bbl compared to $23.39 per Bbl in
the same period a year ago, which included a loss of 5 cents per Bbl from
hedging activities. The lower natural gas prices reduced after-tax earnings by
approximately $200 million, while the lower liquids prices reduced after-tax
earnings by approximately $35 million. Natural gas production in North America
was 910 MMcf/d in the nine months period of 2002 compared to 1,131 MMcf/d in the
same period a year ago. This decline reflected primarily lower natural gas
production from the Gulf of Mexico shelf area including production from the Muni
field, which averaged 11 MMcf/d, net of royalty, in the nine months period of
2002 compared to 107 MMcf/d, net of royalty, during the nine months period of
2001. In addition, reduced second-half 2001 drilling activity compared with the
first half of 2001 was a factor in the lower production levels. Lower natural
gas production reduced after-tax earnings by approximately $170 million.
-31-
The results in the nine months period of 2002 also included the $12 million
after-tax impairment in Alaska and the $12 million after-tax restructuring
provision for the Gulf Region business unit. The nine months period of 2001
included an after-tax gain of $5 million in mark-to-market accruals and realized
gains and losses for non-hedge commodity derivatives by Northrock, while the
nine months of 2002 had a $5 million after-tax loss. Dry hole costs in the nine
months period of 2002 were lower by $20 million after-tax than in the same
period a year ago, primarily due to lower drilling activity in the Gulf of
Mexico, partially offset by higher dry hole costs in Alaska.
Restructuring: In June 2002, the Company adopted a restructuring plan that
resulted in a $12 million after-tax restructuring charge. The restructuring
charge covered the costs of terminating approximately 200 employees in the
Company's Sugar Land, Texas, office and field locations. All of the affected
employees had been terminated as of September 30, 2002. The restructuring plan
involved organizational changes to eliminate unnecessary work processes in the
Company's Gulf Region business unit, which is part of the U.S. Lower 48
operations.
The restructuring charge was included in the results of the U.S. Lower 48
section of the Exploration & Production segment. Cash expenditures related to
the restructuring plan are expected to total approximately $9 million in the
second half of 2002 and $7 million in 2003. The Company expects the plan to
reduce future salaries and benefits by an estimated $20 million pre-tax
annually.
International - Unocal's International operations include oil and gas
exploration and production activities outside of North America. The Company
operates or participates in production operations in Thailand, Indonesia,
Myanmar, Bangladesh, the Netherlands, Azerbaijan, the Democratic Republic of
Congo and Brazil. International operations also include the Company's
exploration and development activities primarily in Asia, Latin America and West
Africa.
Third Quarter Results: After-tax earnings totaled $136 million in the third
quarter of 2002 compared to $111 million in the same period a year ago, which
was an increase of $25 million. The increase was due to $16 million in higher
liquids production, $12 million in lower tax expense due to lower effective tax
rates, primarily due to changes in the Thai baht/U.S. dollar exchange rate, $9
million in lower dry hole costs, $6 million in higher natural gas and liquids
prices, and $5 million in higher natural gas production. These positive factors
were partially offset by $12 million in higher operating expenses and $10
million in higher DD&A expense. Liquids sales volumes increased primarily from
oil production in Thailand, which began in the third quarter of
2001. Dry hole costs in the third quarter of 2002 were lower primarily due to
exploratory dry holes recorded during the third quarter of 2001 in Brazil and
Indonesia. The average liquids price for International operations was $24.80 per
Bbl in the third quarter of 2002, which was an increase of $1.15 per Bbl, or 5
percent, from the same period a year ago. Natural gas production in
International operations was 942 MMcf/d in the nine months period of 2002
compared to 899 MMcf/d in the same period a year ago. This increase was
primarily the result of higher production in Myanmar, Thailand and Bangladesh.
Nine Months Results: After-tax earnings totaled $363 million in the nine months
period of 2002 compared to $357 million in the same period a year ago, which was
an increase of $6 million. The increase was primarily due to $20 million in
lower dry holes costs, $13 million in higher liquids and natural gas production,
$8 million in higher natural gas prices, and a $4 million gain related to
foreign exchange rates. Dry hole costs for the nine months period of 2002 were
lower primarily due to the 2001 exploratory dry holes in Brazil and Gabon and
lower Indonesia dry holes in the current year. Liquids production increased by
approximately 7 percent primarily from higher oil production in Thailand.
Natural gas production increased 3 percent, primarily from Myanmar.
The average natural gas price for International operations was $2.60 per Mcf in
the nine months period of 2002 compared with $2.57 per Mcf in the same period a
year ago. These positive factors were partially offset by $17 million in lower
liquids prices, $15 million in higher operating expenses and $9 million in
higher DD&A expense. The average liquids price for International operations was
$22.62 per Bbl in the nine months period of 2002, which was a decrease of $1.98
per Bbl, or 8 percent, from the same period a year ago.
-32-
OPERATING HIGHLIGHTS UNOCAL CORPORATION
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
----------------------------------------
2002 2001 2002 2001
--------------------------------------------------------------------------------
North America Net Daily Production
Liquids (thousand barrels)
Lower 48 (a) (b) 52 60 54 58
Alaska 24 26 25 25
Canada 16 16 17 15
--------------------------------------------------------------------------------
Total liquids 92 102 96 98
Natural gas - dry basis (million cubic feet)
Lower 48 (a) (b) 716 939 740 922
Alaska 61 83 79 104
Canada 90 92 91 105
--------------------------------------------------------------------------------
Total natural gas 867 1,114 910 1,131
North America Average Prices (excluding hedging activities) (c) (d)
Liquids (per barrel)
Lower 48 $ 24.76 $ 23.08 $ 22.19 $ 24.71
Alaska $ 22.17 $ 21.58 $ 19.41 $ 22.18
Canada $ 22.70 $ 20.89 $ 20.29 $ 20.74
Average $ 23.70 $ 22.35 $ 21.12 $ 23.44
Natural gas (per mcf)
Lower 48 $ 2.95 $ 2.71 $ 2.77 $ 4.71
Alaska $ 1.20 $ 1.57 $ 1.48 $ 1.30
Canada $ 2.08 $ 2.69 $ 2.38 $ 4.90
Average $ 2.73 $ 2.62 $ 2.61 $ 4.40
--------------------------------------------------------------------------------
North America Average Prices (including hedging activities) (c) (d)
Liquids (per barrel)
Lower 48 $ 24.74 $ 23.11 $ 22.22 $ 24.63
Alaska $ 22.17 $ 21.58 $ 19.41 $ 22.18
Canada $ 22.70 $ 20.89 $ 20.29 $ 20.74
Average $ 23.69 $ 22.37 $ 21.14 $ 23.39
Natural gas (per mcf)
Lower 48 $ 2.97 $ 2.97 $ 2.86 $ 4.76
Alaska $ 1.20 $ 1.57 $ 1.48 $ 1.30
Canada $ 2.10 $ 2.76 $ 2.44 $ 3.40
Average $ 2.74 $ 2.85 $ 2.69 $ 4.29
--------------------------------------------------------------------------------
(a) Includes proportional shares of production of equity investees.
(b) Includes minority interest shares of :
Liquids 8 9 8 9
Natural gas 94 111 96 100
Barrels oil equivalent 24 27 24 25
(c) Excludes Trade segment margins.
(d) Excludes gains/losses on derivative positions not accounted for as hedges
and ineffective portions of hedges.
-33-
OPERATING HIGHLIGHTS (CONTINUED) UNOCAL CORPORATION
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
----------------------------------------
2002 2001 2002 2001
--------------------------------------------------------------------------------
International Net Daily Production (e)
Liquids (thousand barrels)
Far East 52 49 53 49
Other (a) 20 19 20 19
--------------------------------------------------------------------------------
Total liquids 72 68 73 68
Natural gas - dry basis (million cubic feet)
Far East 859 833 855 845
Other (a) 83 66 79 64
--------------------------------------------------------------------------------
Total natural gas 942 899 934 909
International Average Prices (f)
Liquids (per barrel)
Far East $ 23.93 $ 23.04 $ 21.95 $ 24.02
Other $ 26.94 $ 25.27 $ 24.62 $ 26.04
Average $ 24.80 $ 23.65 $ 22.62 $ 24.60
Natural gas (per mcf)
Far East $ 2.68 $ 2.62 $ 2.59 $ 2.54
Other $ 2.80 $ 2.80 $ 2.70 $ 2.90
Average $ 2.69 $ 2.63 $ 2.60 $ 2.57
--------------------------------------------------------------------------------
Worldwide Net Daily Production (a) (b) (e)
Liquids (thousand barrels) 164 170 169 166
Natural gas - dry basis (million cubic feet)1,809 2,013 1,844 2,040
Barrels oil equivalent (thousands) 466 506 476 506
Worldwide Average Prices (excluding hedging activities) (c) (d)
Liquids (per barrel) $ 24.20 $ 22.86 $ 21.76 $ 23.92
Natural gas (per mcf) $ 2.71 $ 2.63 $ 2.61 $ 3.57
Worldwide Average Prices (including hedging activities) (c) (d)
Liquids (per barrel) $ 24.19 $ 22.87 $ 21.77 $ 23.89
Natural gas (per mcf) $ 2.72 $ 2.75 $ 2.65 $ 3.51
--------------------------------------------------------------------------------
(a) Includes proportional shares of production of equity investees.
(b) Includes minority interest shares of :
Liquids 8 9 8 9
Natural gas 94 111 96 100
Barrels oil equivalent 24 27 24 25
(c) Excludes Trade segment margins.
(d) Excludes gains/losses on derivative positions not accounted for as hedges
and ineffective portions of hedges.
(e) International production is presented utilizing the economic
interest method.
(f) International did not have any hedging activities.
-34-
TRADE
The Trade segment externally markets the majority of the Company's worldwide
liquids production, excluding that of Pure, and North American natural gas
production, excluding that of Pure and the Alaska business unit. It is also
responsible for executing various derivative contracts on behalf of the
Company's Exploration and Production segment, excluding Pure, in order to manage
the Company's exposure to commodity price changes. The Trade segment also
purchases liquids and natural gas from certain of the Company's royalty owners,
joint venture partners and unaffiliated oil and gas producing and trading
companies for resale. In addition, the segment trades hydrocarbon derivative
instruments, for which hedge accounting is not used, to exploit anticipated
opportunities arising from commodity price fluctuations. The segment also
purchases limited amounts of physical inventories for energy trading purposes
when arbitrage opportunities arise. These commodity risk-management and trading
activities are subject to internal restrictions, including value at risk limits,
which measure the Company's potential loss from likely changes in market prices.
Third Quarter Results: The results for the third quarter of 2002 were a loss of
$1 million after-tax compared to after-tax earnings of $3 million in the same
period a year ago. The lower results reflect decreased domestic natural gas and
crude oil marketing activities due to lower production from the U.S. Lower 48
operations of the Company's Exploration and Production segment.
Sales and operating revenues were $623 million in the third quarter of 2002
compared to $861 million in the same period a year ago, which was a decrease of
$238 million. These revenues represented approximately 48 percent and 55 percent
of the Company's total sales and operating revenues for the third quarters of
2002 and 2001, respectively. In the third quarter of 2002, crude oil revenues
declined by $189 million, primarily due to reduced activity in the purchase and
resale of third party barrels intended to take advantage of marketing
opportunities, reflecting management's continued efforts to decrease its outside
crude oil purchases for resale due to increased volatility in the oil markets.
Natural gas revenues declined by $47 million, primarily due to lower U.S.
domestic production volumes.
Nine Months Results: After-tax earnings totaled $1 million in the nine months
period of 2002 compared to $10 million in the same period a year ago. The lower
results reflect decreased domestic natural gas and crude oil marketing
activities due to lower production from the U.S. Lower 48 operations of the
Company's Exploration and Production segment.
Sales and operating revenues were $1.723 billion in the nine months period of
2002 compared to $3.289 billion in the same period a year ago, which was a
decrease of $1.566 billion. These revenues represented approximately 47 percent
and 60 percent of the Company's total sales and operating revenues for the nine
months periods of 2002 and 2001, respectively. In the nine months period of
2002, crude oil revenues declined by $883 million, primarily due to reduced
activity in the purchase and resale of third party barrels intended to take
advantage of marketing opportunities, reflecting management's continued efforts
to decrease its outside crude oil purchases for resale due to increased
volatility in the oil markets. Natural gas revenues declined by $686 million
primarily due to lower commodity prices and lower U.S. domestic production
volumes.
MIDSTREAM
The Midstream segment is comprised of the Company's equity interests in
petroleum pipeline companies, wholly-owned pipeline systems throughout the U.S.,
and the Company's North America gas storage business.
Third Quarter Results: After-tax earnings totaled $17 million in the third
quarter of 2002 compared to $13 million in the same period a year ago. The
increase was due primarily to $7 million in improved throughput volumes from the
pipeline business and $3 million in improved results in the gas storage
business, which were partially offset by $4 million in after-tax litigation
provision and project impairment charge related to the Colonial Pipeline Company
and a $2 million after-tax asset impairment related to another U.S. pipeline
company in which the Company owns an equity interest.
-35-
Nine Months Results: After-tax earnings totaled $59 million in the nine months
period of 2002 compared to $40 million in the same period a year ago. The
increase was due primarily to $10 million in improved throughput volumes from
the pipeline business. In addition, after-tax earnings in the gas storage
business in the first nine months of 2002 improved by $9 million compared with
the same period a year ago.
GEOTHERMAL AND POWER OPERATIONS
The Geothermal and Power Operations business segment produces geothermal steam
for power generation, with operations in the Philippines and Indonesia. The
segment's activities also include the operation of power plants in Indonesia and
equity interests in gas-fired power plants in Thailand. The Company's
non-exploration and production business development activities, primarily
power-related, are also included in this segment.
Third Quarter Results: After-tax earnings totaled $5 million in the third
quarter of 2002 compared to $2 million in the same period a year ago. The
improved results were due to approximately $9 million after-tax in lower
receivable provisions related to geothermal operations in Indonesia, partially
offset by lower steam sales due to lower electricity generation.
Nine Months Results: After-tax earnings totaled $25 million in the nine months
period of 2002 compared to $5 million in the same period a year ago. The
improved results were due to approximately $23 million after-tax in lower
receivable provisions related to geothermal operations in Indonesia.
Agreements Reached on Indonesia Geothermal Contracts: In July 2002, the
Company's Unocal Geothermal of Indonesia, Ltd. ("UGI"), subsidiary and Dayabumi
Salak Pratama, Ltd. ("DSPL"), a 50-percent equity investee of UGI, reached
agreement over pricing and production issues at its Gunung Salak geothermal
project in Indonesia with PT. PLN (Persero) ("PLN"), the Indonesian state-owned
electricity company, and Pertamina, the Indonesian state-owned oil and natural
gas company.
Gunung Salak is a 330-megawatt (nominal installed nameplate rating) geothermal
production and electricity generation project on the western side of the island
of Java. UGI operates the steam fields as a contractor to Pertamina and delivers
geothermal steam to PLN, which operates three electricity-generating plants at
Salak. UGI also delivers steam to DSPL for three generating plants that supply
electricity to PLN on behalf of Pertamina.
The new agreement extends the primary terms of the Joint Operation Contract and
Energy Sales Contract ("ESC") to 2040. The new agreement increases the Unit
Rated Capacities for the generating plants operated by DSPL by 32 megawatts
thereby increasing minimum take-or-pay amounts payable under the ESC and also
includes a commitment by PLN to accept as much steam and electricity as possible
over the take-or-pay quantities in order to meet increased demand. In addition,
the agreement reaffirms the Government of Indonesia guarantee of PLN's
obligations to UGI, DSPL, Pertamina and the project's lenders.
The new agreement lowers the selling price of electricity delivered by DSPL from
8.49 cents per kilowatt-hour (kWh) to 4.45 cents per kWh and steam supplied to
PLN by UGI from 4.25 cents per kWh to 3.72 cents per kWh. Under the terms of the
amended ESC both the selling price for electricity and the selling price for
geothermal steam are indexed for changes in foreign exchange rates and
inflation.
The new agreement also provides for payment by PLN of a portion of the past due
receivable balances to the Company while the Company foregoes a portion of the
receivables. In July 2002, the Company received $51 million from PLN in payment
of a portion of the past due receivable balances. The Company will retain a
receivable balance of $93 million plus interest and expects to collect in full
this amount over a period of approximately four years. The remaining part of the
outstanding receivables was written-off against a previously established
allowance for bad debts.
-36-
CORPORATE AND OTHER
Corporate and Other includes general corporate overhead, miscellaneous
operations (e.g., real estate activities, carbon and minerals) and other
corporate unallocated costs. Net interest expense represents interest expense,
net of interest income and capitalized interest.
Third Quarter Results: The after-tax earnings effect for the third quarter of
2002 was a loss of $79 million compared to a loss of $101 million in the same
period a year ago. Lower after-tax expenses for environmental and litigation
matters benefited the third quarter of 2002, with expenses of $25 million
after-tax compared to $30 million after-tax for the same period a year ago. The
third quarter of 2002 reflected $10 million in higher results from the carbon,
minerals and real estate business activities, compared to the same period a year
ago. Net interest expense was $3 million lower in the third quarter of 2002
compared to the same period a year ago, primarily due to higher capitalized
interest on development projects. The third quarter of 2002 reflected $3 million
in lower employee related compensation, as compared to the third quarter of
2001. The results in the third quarter of 2002 included $7 million in higher
pension related expenses.
Nine Months Results: The after-tax earnings effect for the nine months period of
2002 was a loss of $245 million compared to a loss of $283 million in the same
period a year ago. Lower after-tax provisions for environmental and litigation
matters benefited the nine months period of 2002, with expenses of $63 million
after-tax compared to $80 million after-tax for the same period a year ago. The
nine months period of 2002 also reflected $9 million in higher minerals results,
compared to the same period a year ago. Lower income tax related adjustments in
the nine months period of 2002, as compared to the same period of 2001,
benefited earnings by $11 million. The nine months period of 2002 benefited from
a $2 million after-tax gain from an insurance settlement reached with
insurers for the recovery of amounts previously paid out for environmental
pollution claims and related costs. The nine months period of 2001 included a
$10 million pre-tax, or $7 million after-tax, contribution to a charitable
foundation, while the comparable period of 2002 included a similar contribution
of $3 million pre-tax, or $2 million after-tax. The results for the nine months
period of 2002 included $18 million in higher pension related expenses. The nine
months of 2002 included $9 million after-tax in pension related expenses,
compared to income of $9 million after-tax in the nine months period of 2001.
Net interest expense was $3 million lower in the nine months period of 2002, as
higher interest expense from a premium on an early repayment of long-term debt
was more than offset by higher capitalized interest on development projects.
-37-
At At At
September 30, December 31, September 30,
-------------------------------------------------
Millions of dollars 2002 2001 2001
--------------------------------------------------------------------------------
Current ratio 0.8:1 0.9:1 1.1:1
Total debt and capital leases $ 3,078 $ 2,906 $ 2,859
Trust convertible
preferred securities 522 522 522
Stockholders' equity 3,182 3,124 3,201
-------------------------------------------------
Total capitalization $ 6,782 $ 6,552 $ 6,582
=================================================
Floating-rate debt/total debt 21% 8% 6%
--------------------------------------------------------------------------------
Cash flows from operating activities, including discontinued operations and
working capital and other changes, were $1.23 billion for the nine months period
of 2002 compared to $1.78 billion in the same period a year ago. This decrease
principally reflected the effects of lower worldwide average natural gas and
liquids prices. The decrease was partially offset by $143 million in lower
income tax payments, net of refunds, compared to the nine months period of 2001,
$30 million from the sale of certain domestic trade receivables during the nine
months period of 2002 and the receipt of $51 million from PLN in July 2002 for
payment of past due receivables as a result of the agreement reached on the
Indonesia geothermal contracts at Gunung Salak.
Pre-tax proceeds from asset sales, including those classified as discontinued
operations, were $64 million for the nine months period of 2002. Proceeds of
approximately $29 million were from the sale, by the Company's Pure subsidiary,
of oil and gas producing properties in the U.S. Sale proceeds also included $17
million from various other oil and gas asset sales, $15 million in other
miscellaneous properties and $3 million related to a participation payment
received from the purchaser of the Company's former West Coast refining,
marketing and transportation assets covering price differences between
California Air Resources Board Phase 2 gasoline and conventional gasoline. For
the nine months period of 2001, pre-tax proceeds from asset sales, including
those classified as discontinued operations, were $51 million. The proceeds
included $25 million related to a participation payment received from the
purchaser of the Company's former West Coast refining, marketing and
transportation assets, $14 million from the sale of certain oil and gas
properties and $12 million from the sale of miscellaneous assets.
Capital expenditures in the nine months period of 2002 were $1.25 billion,
compared with $1.26 billion in the same period a year ago. The capital
expenditures amount for the nine months period of 2001 excluded $536 million in
major acquisitions, which is reflected as a separate line on the consolidated
cash flows statement. For the full year 2002, total capital expenditures,
excluding major acquisitions, are currently expected to be approximately $1.7
billion. Of this total, about 93 percent is expected to be spent in support of
exploration and development programs, evenly split between North America and
International operations. The remainder of the capital expenditures will be
spent on Midstream and Geothermal and Power operations and corporate-related
expenditures.
The Company has taken appropriate action to help mitigate credit exposure to
counterparties whose creditworthiness has deteriorated since the beginning of
the year. Counterparty credit lines have been reduced substantially or rescinded
entirely where it has been determined that there is unwarranted credit exposure.
In other instances, credit assurances in the form of prepayments, letters of
credit or guarantees have been obtained to support the credit extension.
-38-
The Company's long-term debt, including the current portion, was $3.08 billion
at September 30, 2002, compared with $2.91 billion at year-end 2001. This
increase primarily reflected commercial paper borrowings made by the Company to
fund scheduled maturing fixed-rate debt and for other general corporate purposes
(see note 10 for further detail on the Company's long-term debt). On October 3,
2002, the Company issued $400 million principal amount of 5.05 percent notes
with a maturity date of October 1, 2012. The net proceeds from the sale of the
notes were used to repay most of the outstanding commercial paper borrowings. At
October 31, 2002, the Company's outstanding balance of commercial paper
borrowings was approximately $55 million compared to $437 million outstanding at
September 30, 2002.
The Company has two credit facilities in place: a $400 million 364-day credit
agreement and a $600 million 5-year credit agreement. On October 7, 2002, the
Company extended the 364-day credit agreement to October 6, 2003. The agreements
provide for the termination of their loan commitments and require the prepayment
of all outstanding borrowings in the event that (1) any person or group becomes
the beneficial owner of more than 30 percent of the then outstanding voting
stock of Unocal other than in a transaction having the approval of Unocal's
board of directors, at least a majority of which are continuing directors, or
(2) if continuing directors shall cease to constitute at least a majority of the
board. The agreements do not have drawdown restrictions or prepayment
obligations in the event of a credit rating downgrade.
Based on current commodity prices and current development projects, the Company
does not expect cash generated from operating activities, asset sales and cash
on hand in 2002 to be sufficient to cover its operating and capital spending
requirements and to meet dividend payments. The Company has substantial
borrowing capacity to enable it to meet anticipated and unanticipated cash
requirements. The Company relies on the commercial paper market on an interim
basis, its accounts receivable securitization program and its revolving credit
facilities to cover short-term borrowing requirements. The Company decreased the
funding availability of its accounts receivable securitization program to $125
million from $204 million in 2002. At September 30, 2002, the Company had sold
$100 million of its domestic trade receivables under this program. The Company
also has in place a universal shelf registration statement with an unutilized
balance of approximately $739 million at September 30, 2002, under which it
issued the $400 million of notes discussed above, leaving $339 million of
SEC-registered securities, which can be issued as debt and/or equity securities
in the future, depending on the Company's needs and market conditions. From time
to time, the Company may also look to fund some of its long-term projects using
other financing sources, including multilateral and bilateral agencies.
Maintaining investment-grade credit ratings, i.e., "BBB- / Baa3" and above from
Standard & Poor's Ratings Services and Moody's Investors Service, Inc.,
respectively, is a significant factor in the Company's ability to raise
short-term and long-term financing. As a result of the Company's current
investment grade ratings, the Company has access to both the commercial paper
and bank loan markets. The Company currently has a BBB+ / Baa2 credit rating by
Standard & Poor's and Moody's, respectively. In September 2002, Moody's
downgraded the Company's credit rating to Baa2 from Baa1 and maintained a stable
rating outlook on the Company. In September 2002, Standard & Poor's affirmed its
rating for the Company's long-term debt. Moody's and Standard & Poor's outlook
remained stable for the Company's Prime-2 and A-2 commercial paper ratings,
respectively. As outlined in the tables on pages 40 and 41 of Management's
Discussion and Analysis in Item 7 of the Company's amended 2001 Annual Report on
Form 10-K/A, the Company continues to believe that it does not have a liquidity
exposure in the event of a further credit rating downgrade. In the event that
the Company's credit ratings were to fall to levels that would prohibit it from
accessing the commercial paper markets, the Company expects that it would still
be able to access funds under its revolving credit facilities.
-39-
ENVIRONMENTAL MATTERS
At September 30, 2002, the Company's reserves for environmental remediation
obligations totaled $242 million, of which $126 million were included in current
liabilities. During the nine months ended September 30, 2002, cash payments of
$77 million were applied against the reserves and $82 million in provisions were
added to the reserves balance. The Company may also incur additional liabilities
in the future at sites where remediation liabilities are probable but future
environmental costs are not presently reasonably estimable because the sites
have not been assessed or the assessments have not advanced to stages where
costs are reasonably estimable. At those sites where investigations or
feasibility studies have advanced to the stage of analyzing feasible alternative
remedies and/or ranges of costs, the Company estimates that it could incur
possible additional remediation costs aggregating approximately $245 million.
The Company's total environmental reserve and possible additional liability
amounts are grouped into the following four categories.
At September 30, 2002
----------------------------
Possible
Millions of dollars Reserves Additional
--------------------------------------------------------------------------------
Superfund and similar sites $ 18 $ 11
Active Company facilities 38 63
Company facilities sold with retained liabilities
and former Company-operated sites 90 69
Inactive or closed Company facilities 96 102
--------------------------------------------------------------------------------
Total reserves $ 242 $ 245
================================================================================
Also see notes 11 and 12 to the consolidated financial statements in Item 1 of
this report for additional information on environmental related matters.
In the third quarter of 2002, provisions of $33 million were recorded. The
provisions reflected an $18 million increase in remediation cost estimates for
sites included in the Company's "Inactive or closed Company facilities"
category. This additional amount is principally for the decommissioning and
decontamination of closed molybdenum and rare earth processing facilities of the
Company's Molycorp, Inc. subsidiary in Washington and York, Pennsylvania. As a
result of ongoing cooperative efforts between the Company and the Nuclear
Regulatory Commission, it was determined that it was probable that additional
volumes of low-level radioactive contaminated material, in excess of amounts
previously estimated, need to be removed at the York and Washington sites. The
provisions also reflected an $11 million increase in cost estimates for sites
included in the "Company facilities sold with retained liabilities and former
Company-operated sites" category. The provisions for these sites reflects
primarily revised remediation cost estimates that the Company has received from
the purchaser of service stations, bulk plants, terminals, refineries and
pipelines that were part of the Company's "downstream" business sold in 1997. In
addition, the provisions include increases for approximately 50 other sites in
this category. The remaining $4 million of the provisions relate to six sites in
the "Active Company facilities" and Superfund and similar sites" categories of
reported remediation costs. Most of the $33 million was included in the
Company's reported June 30, 2002 estimate of possible additional remediation
costs.
Possible additional costs in excess of amounts included in the reserves for
remediation obligations decreased by $10 million in the third quarter of 2002.
The Company decreased its estimated costs by $5 million for the "Inactive or
closed Company facilities" category of sites, primarily for the York and
Washington, Pennsylvania facilities. These costs were included in the amounts
added to the reserve in the third quarter. Partially offsetting this decrease
are additional estimates for the Washington site for the estimated costs to
remove and dispose of additional contamination that could be present at the
site. Estimated possible additional costs for the "Company facilities sold with
retained liabilities and former Company-operated sites" category decreased by $2
million primarily due to adding the estimated costs for the Company's sold
downstream assets sold in 1997 to the reserve. Possible additional costs for the
"Active Company facilities" category were decreased by $3 million. These costs
were also added to the reserve in the third quarter.
-40-
During the first and second quarters of 2002, provisions of $49 million were
added to the reserve balance. Provisions of $33 million were recorded for the
"Company facilities sold with retained liabilities and former Company-operated
sites" category. These provisions were the result of revised cost estimates
related to the anticipated cleanup of the Company's former service stations and
distribution facilities throughout the U.S. The provisions also included the
estimated cost to cleanup contaminated areas that have been identified at a
former oil field in Michigan. Provisions of $9 million were recorded for sites
included in the "Inactive or closed Company facilities" category primarily for
revised cost estimates related to various remediation projects at the Company's
former Guadalupe oil field on the central California coast. Additional accruals
of $7 million for the "Superfund and similar sites" category were recorded. The
accrual was primarily for the Company's estimated remaining share of oversight
and monitoring costs related to the McColl Superfund site in Fullerton,
California as the result of a federal appeals court overturning a 1998 court
decision that held the federal government responsible for cleanup of the site
because of its role in encouraging oil companies to produce gasoline during
World War II.
OUTLOOK
Certain of the statements in this discussion, as well as other forward-looking
statements within this document, contain estimates and projections of amounts of
or increases / decreases in future revenues, earnings, cash flows, capital
expenditures, assets, liabilities and other financial items and of future levels
of or increases / decreases in reserves, production, sales including related
costs and prices, drilling activities and other statistical items; plans and
objectives of management regarding the Company's future operations, products and
services; and certain assumptions underlying such estimates, projection plans
and objectives. While these forward-looking statements are made in good faith,
future operating, market, competitive, legal, economic, political,
environmental, and other conditions and events could cause actual results to
differ materially from those in the foward-looking statements. See pages 51
through 53 of Management's Discussion and Analysis in Item 7 of the Company's
amended 2001 Annual Report on Form 10-K/A for a discussion of certain of such
conditions and events.
Volatile energy prices are expected to continue to impact financial results. The
Company expects energy prices to remain volatile due to changes in climate
conditions, worldwide demand, crude oil and natural gas inventory levels,
production quotas set by OPEC, current and future worldwide political
instability, especially events concerning Iraq, and security and other factors.
The economic situation in Asia, where most of the Company's international
activity is centered, is still recovering with positive signs showing in the
region. The Company looks at the natural gas market in Asia as one of its major
strategic investments and believes that the governments in the region are
committed to undertaking the reforms and restructuring necessary to enable their
nations to continue their recoveries from the downturn.
The Company estimates that its net worldwide daily production for 2002 will
average between 469,000 and 472,000 BOE. Early in the fourth quarter of 2002,
the Company sustained significant, temporary production losses in the Gulf of
Mexico as a result of Hurricane Lili. The Company's best estimates for fourth
quarter production, including the effect of the hurricane, are between 445,000
and 460,000 BOE per day. The Company estimates net earnings per share to be
between 50 and 60 cents in the fourth quarter of 2002. The fourth quarter
forecast assumes average NYMEX benchmark prices of $29.75 per barrel of crude
oil and $4.10 per MMBtu for North America natural gas. The fourth quarter
forecasted earnings are expected to change 4 cents per share for every $1 change
in its average worldwide realized price for crude oil and 2 cents per share for
every 10-cent change in the Company's average realized North America natural gas
price. The fourth quarter forecast also includes pre-tax dry hole costs of $25
to $35 million. In addition, the fourth quarter forecast also includes pre-tax
losses, net of insurance recoveries, of approximately $15 million as a result of
the damage from Hurricane Lili. The Company estimates net earnings per share to
be between $1.46 to $1.56 for the full year 2002.
-41-
Exploration and Production - North America
U.S. Lower 48: Hurricane Lili affected the Eastern Gulf of Mexico around the
Company's production base in Ship Shoal, Eugene Island and South Marsh Island.
Production shut-ins from the storm and the resulting damage to facilities are
having a significant effect on fourth quarter 2002 production. Production losses
from shut-ins began on October 2 and were as high as 75,000 BOE per day. By
October 10 most of the shut-in production from facilities that did not sustain
major damage was restored. Approximately 15,000 BOE per day remains shut in as
major facility damage assessments and recovery plans were being completed. The
Company has insurance coverage for the damages incurred, subject to a $15
million deductible. The Eastern Gulf area is also where the Company was planning
to spend the majority of its development and workover activities in the fourth
quarter of 2002. A significant number of these projects are currently delayed
pending facility repair. The impact of these project delays on net production is
estimated to be around 4,000 BOE per day in the fourth quarter.
The Company currently expects to resume production by the end of the year from
the remaining damaged facilities. The Company estimates that hurricane-related
impacts will lower fourth quarter production by 15,000 to 23,000 BOE per day.
The Company is currently drilling its second appraisal well, which was delayed
15 days by hurricanes Isidore and Lili, at the Trident discovery in the
deepwater Gulf of Mexico. After completing this well, the Company plans to
commence drilling another deepwater prospect by the end of 2002 or early in
2003. In addition, the Company is continuing its participation in the
development of the Mad Dog discovery.
The Company is continuing to focus its exploration effort on deeper prospects
with higher resource potential in the Gulf of Mexico shelf.
The Company anticipates selling some of its low margin properties in the Gulf
Region towards the end of 2002 or in early 2003.
On October 29, 2002, the Company completed its exchange offer for the remaining
shares of Pure, that it did not already own. In the exchange offer, the Company
exchanged 0.74 shares of Unocal common stock for each share of Pure common stock
it did not already own. The Company accepted tenders of 16,634,625 Pure shares
in the exchange offer, which when combined with the 65 percent of the shares it
already owned, represented approximately 97.5 percent of Pure's outstanding
common shares. On October 30, 2002, the Company completed a short-form merger to
acquire the remaining 2.5 percent of Pure's outstanding shares at the same 0.74
exchange ratio used in the exchange offer. Consequently, Pure is now a wholly
owned subsidiary of the Company. This transaction was valued at approximately
$390 million and eliminated the minority interest liability relating to Pure
and all of the outstanding balance under the caption "Subsidiary stock subject
to repurchase" on the Company's consolidated balance sheet. The transaction will
be reflected in the Company's fourth quarter results. As a consequence of the
acquisition, Standard & Poor's raised its ratings on Pure to BBB+ from BBB-.
Alaska: The Company will be closing two platforms in the Cook Inlet in a move to
better manage overall costs. One platform is expected to be shutdown by the end
of 2002 and the other is expected to be shutdown by the end of the first quarter
of 2003. The two platforms currently have a combined production rate of
approximately 900 b/d of oil. In addition, the Company is analyzing a
restructuring program to streamline operations and improve profitability.
-42-
Exploration and Production - International
Far East
Thailand: The Company's Unocal Thailand, Ltd. ("Unocal Thailand"), subsidiary
expects modest production growth in 2003, with the full-year effect of the Phase
II development in the northern part of the Pailin field in the B12/27 concession
area in the Gulf of Thailand. Unocal Thailand is operator of the field and holds
a 35 percent working interest (31 percent net of royalty). The Company also
expects higher average liquids production, with the full-year effect of crude
oil production from its Yala field. The Company has a 71 percent working
interest in the Yala field (62 percent net of royalty).
Indonesia: The Company's Unocal Rapak, Ltd. ("Unocal Rapak"), subsidiary is
continuing its evaluation of engineering and development studies for the
deepwater Ranggas oil prospect offshore East Kalimantan, Indonesia. Unocal Rapak
is operator of the Rapak PSC area and holds an 80 percent working interest. The
Company is also evaluating early development options for the condensate
discovered at its deepwater Gendalo-Gandang discovery in the Ganal PSC, offshore
Indonesia. The Company's Unocal Ganal, Ltd., subsidiary is the operator of the
Ganal PSC and holds an 80 percent working interest.
In 2003, the Company expects new production from the deepwater West Seno oil and
gas field to come on line in the second quarter. The first phase of development
has peak production potential of more than 52,000 BOE per day net to the
Company, increasing to more than 65,000 BOE per day with the second phase in
2005. Gross development costs for the first phase are expected to be
approximately $460 million, with an additional $225 million for the second phase
(Unocal's net share is expected to be approximately $415 million and $200
million for phases 1 and 2, respectively). The Company and its co-venturer are
currently working to secure financing for a portion of the total costs through
the Overseas Private Investment Corporation ("OPIC"). The Company and its
co-venturer expect to complete financing arrangements with OPIC in late 2002, or
early 2003 for two loans. One loan is $300 million for the first phase, and the
other loan is $50 million for the second phase.
Other International
Azerbaijan: The Azerbaijan International Operating Company ("AIOC") consortium,
in which the Company has a 10.28% working interest, is developing Phases 1 and 2
of the offshore Azeri field in the Azeri-Chirag-Guneshli structure in the
Azerbaijan sector of the Caspian Sea. Phase 1 is to develop an estimated 1.5
billion barrels of proved crude oil reserves and Phase 2 is to add approximately
the same amount of reserves. The Company has approved the expenditure of $310
million and $400 million for its share of the costs for Phases 1 and 2,
respectively. The project is under construction and on schedule with first oil
from the Phase 1 Central Azeri platform expected early in 2005. Phase 2 will
begin production from two additional platforms in 2006. A third phase is in
early engineering and is expected to be approved in 2004. Gross production from
the combined phases, plus the currently producing Early Oil Project in the
Chirag Field, is forecasted to be over 800 MBbl/d by 2009.
Bangladesh: The Company continues to work with the government of Bangladesh and
Petrobangla, the state oil and gas company, to develop additional reserves and
export natural gas to markets in neighboring India. At October 31, 2002, the
Company's business unit in Bangladesh had a gross receivable balance of
approximately $33 million relating to invoices billed for natural gas and
condensate sales to Petrobangla. Approximately $27 million of the outstanding
balance represented past due amounts and accrued interest for invoices covering
April 2002 through September 2002. Generally, invoices, when paid, have been
paid in full. The Company is working with Petrobangla and the government of
Bangladesh regarding the collection of the outstanding receivables. See also
note 12 to the consolidated financial statements in Item 1 of this report for
information regarding a claim made by Petrobangla in 2002 against one of the
Company's subsidiaries for compensation with respect to a 1997 well blowout.
-43-
Midstream
Construction of the Baku-Tbilisi-Ceyhan ("BTC") pipeline started in
mid-September. The pipeline project is planned to have a crude oil capacity of 1
million Bbl/d. Completion of the pipeline is expected in late 2004 at an overall
estimated cost of approximately $3 billion, and the pipeline is expected to be
in operation in early 2005. The Company has an 8.9 percent interest and is one
of eleven shareholders in the BTC pipeline project. The pipeline company
anticipates financing up to 70 percent of the pipeline's cost.
In late October, the Company signed a definitive agreement to sell certain
investment interests in nonstrategic pipelines in the U.S. for approximately $54
million. Closing of the transaction is expected before year-end, subject to
regulatory approval and standard closing conditions.
Geothermal and Power Operations
In the Philippines, negotiations between the Company's wholly-owned subsidiary
Philippines Geothermal, Inc. ("PGI") and two government-owned entities the
National Power Corporation ("NPC") and the Power Sector Assets and Liabilities
Corporation are continuing. These negotiations center on the conversion of PGI's
Service Contract into a Steam Sales Agreement, the rehabilitation of NPC's power
plants at Mak-Ban and Tiwi on the island of Luzon and the requirement for
Filipino ownership. The Company believes that significant progress has been made
towards an agreement that will be acceptable to all parties to resolve the
outstanding issues.
Corporate and Other
Recent declines in the equity markets and interest rates have had a negative
impact on the Unocal Retirement Plan ("Plan"). The fair value of the Plan's
assets at October 22, 2002, was below the Plan's accumulated benefit obligation.
Without a substantial rebound in the equity markets before year-end, a
calculation based on the current fair value of pension assets would require the
Company to take an after-tax charge to stockholders' equity (accumulated other
comprehensive income) at December 31, 2002 for an estimated amount of $330
million. The actual charge to accumulated other comprehensive income will vary
primarily with future 2002 changes in the equity markets and the resultant
change in the fair value of Plan assets and long-term interest rates, but will
have no impact on 2002 net earnings.
For the full-year 2002, pension expense related to the Company's U.S. based
employees is expected to be $14 million after-tax, an increase of approximately
$25 million after-tax compared to the full-year 2001. Lower returns and declines
on plan assets and the use of a lower discount rate to measure benefit-related
liabilities are the principal factors behind the increase in current year
expense. Furthermore, continued lower returns and declines on Plan assets would
result in increased pension expense in future years. The Company will not be
required to make cash contributions to the Plan in 2002, 2003 or 2004.
Continued poor returns on Plan assets could result in accelerating the
requirement to make cash contributions to the Plan after 2004.
-44-
Reformulated Gasoline Patents
The Company's efforts to enforce its patents for reformulated gasoline continue.
In its ongoing lawsuit to collect damages for infringement of the '393 patent
from five California refiners, the U.S. District Court in California has
determined that the 5.75 cent per gallon royalty rate determined by the jury in
the 1997 trial will apply to the defendants' infringing gasoline in California
for the period from August 1996 through December 2000. No determination has been
made by the Court as to the royalty rate for non-California gasoline in this
action. The Company's suit against Valero Energy and its subsidiaries for
infringement of the `393 and `126 patents has been temporarily stayed pending
additional information on the U.S. Patent and Trademark Office ("PTO")
reexaminations.
In June 2002, the PTO initially rejected all of the claims of the '126 patent,
as it had done earlier with the '393 patent, as part of the reexamination
process. In July, the PTO granted a second request for reexamination of the '393
patent based on additional alleged prior art. The second reexamination of the
`393 patent has now been merged with the first. The Company is awaiting a
response from the PTO to its submission arguing against the initial
rejections of both the `393 and `126 patents.
The Federal Trade Commission has been conducting a non-public investigation of
allegations of anticompetitive conduct in enforcement of the Company's patents.
The Company has not received notice of whether a determination or conclusion has
been reached as a result of the investigation.
FUTURE ACCOUNTING CHANGES
In August 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No 143, "Accounting for
Asset Retirement Obligations". It is effective for fiscal years beginning after
June 15, 2002, and it requires entities to record the fair value of a liability
for an asset retirement obligation in the period in which it is incurred, as a
capitalized cost of the long-lived asset and to depreciate it over the useful
life of the asset. The Company is currently in the process of evaluating the
impact that SFAS No. 143 will have on its financial position and results of
operations.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities". This statement provides guidance on the
recognition and measurement of liabilities associated with disposal activities
and is effective for the Company on January 1, 2003. The Company does not expect
the adoption of SFAS No. 146 to have a significant impact on its financial
position and results of operations.
Other proposed accounting changes considered from time to time by the FASB, the
U.S. SEC and the United States Congress could materially impact the Company's
reported financial position and results of operations.
-45-
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Market risk generally represents the risk that losses may occur in the values of
financial instruments as a result of changes in interest rates, foreign currency
exchange rates and commodity prices. As part of its overall risk management
strategies, the Company uses derivative financial instruments to manage and
reduce risks associated with these factors. The Company also trades hydrocarbon
derivative instruments, such as futures contracts, swaps and options to exploit
anticipated opportunities arising from commodity price fluctuations.
The Company determines the fair values of its derivative financial instruments
primarily based upon market quotes of exchange traded instruments. Most futures
and options contracts are valued based upon direct exchange quotes or industry
published price indices. Some instruments with longer maturity periods require
financial modeling to accommodate calculations beyond the horizons of available
exchange quotes. These models calculate values for outer periods using current
exchange quotes (i.e., forward curve) and assumptions regarding interest rates,
commodity and interest rate volatility and, in some cases, foreign currency
exchange rates. While the Company feels that current exchange quotes and
assumptions regarding interest rates and volatilities are appropriate factors to
measure the fair value of its longer termed hydrocarbon derivative instruments,
other pricing assumptions or methodologies may lead to materially different
results in some instances.
Interest Rate Risk - From time to time the Company temporarily invests its
excess cash in short-term interest-bearing securities issued by high-quality
issuers. Company policies limit the amount of investment in securities of any
one financial institution. Due to the short time the investments are outstanding
and their general liquidity, these instruments are classified as cash
equivalents in the consolidated balance sheet and do not represent a material
interest rate risk to the Company. The Company's primary market risk exposure
for changes in interest rates relates to the Company's long-term debt
obligations. The Company manages its exposure to changing interest rates
principally through the use of a combination of fixed and floating rate debt.
Interest rate risk sensitive derivative financial instruments, such as swaps or
options may also be used depending upon market conditions.
The Company evaluated the potential effect that near term changes in interest
rates would have had on the fair value of its interest rate risk sensitive
financial instruments at September 30, 2002. Assuming a ten percent decrease in
the Company's weighted average borrowing costs at September 30, 2002, the
potential increase in the fair value of the Company's debt obligations and
associated interest rate derivative instruments, including the Company's net
interests in the debt obligations and associated interest rate derivative
instruments of its subsidiaries, would have been approximately $87 million at
September 30, 2002.
Foreign Exchange Rate Risk - The Company conducts business in various parts of
the world and in various foreign currencies. To limit the Company's foreign
currency exchange rate risk related to operating income, foreign sales
agreements generally contain price provisions designed to insulate the Company's
sales revenues against adverse foreign currency exchange rates. In most
countries, energy products are valued and sold in U.S. dollars and foreign
currency operating cost exposures have not been significant. In other countries,
the Company is paid for product deliveries in local currencies but at prices
indexed to the U.S. dollar. These funds, less amounts retained for operating
costs, are converted to U.S. dollars as soon as practicable. The Company's
Canadian subsidiaries are paid in Canadian dollars for their crude oil and
natural gas sales.
From time to time the Company may purchase foreign currency options or enter
into foreign currency swap or foreign currency forward contracts to limit the
exposure related to its foreign currency debt or other obligations. At September
30, 2002, the Company had various foreign currency swaps and foreign currency
forward contracts outstanding related to operations in Canada, Thailand and The
Netherlands. The Company evaluated the effect that near term changes in foreign
exchange rates would have had on the fair value of the Company's combined
foreign currency position related to its outstanding foreign currency swaps and
forward contracts.
-46-
Assuming an adverse change of ten percent in foreign exchange rates at September
30, 2002, the potential decrease in fair value of the Company's foreign currency
forward contracts, foreign-currency denominated debt, foreign currency swaps and
foreign currency forward contracts of its subsidiaries, would have been
approximately $14 million at September 30, 2002.
Commodity Price Risk - The Company is a producer, purchaser, marketer and trader
of certain hydrocarbon commodities such as crude oil and condensate, natural gas
and refined products and is subject to the associated price risks. The Company
uses hydrocarbon price-sensitive derivative instruments ("hydrocarbon
derivatives"), such as futures contracts, swaps, collars and options to mitigate
its overall exposure to fluctuations in hydrocarbon commodity prices. The
Company may also enter into hydrocarbon derivatives to hedge contractual
delivery commitments and future crude oil and natural gas production against
price exposure. The Company also actively trades hydrocarbon derivatives,
primarily exchange regulated futures and options contracts, subject to internal
policy limitations.
The Company uses a variance-covariance value at risk model to assess the market
risk of its hydrocarbon derivatives. Value at risk represents the potential loss
in fair value the Company would experience on its hydrocarbon derivatives, using
calculated volatilities and correlations over a specified time period with a
given confidence level. The Company's risk model is based upon historical data
and uses a three-day time interval with a 97.5 percent confidence level. The
model includes offsetting physical positions for hydrocarbon derivatives related
to the Company's fixed price pre-paid crude oil and pre-paid natural gas sales.
The model also includes the Company's net interests in its subsidiaries' crude
oil and natural gas hydrocarbon derivatives and forward sales contracts. Based
upon the Company's risk model, the value at risk related to hydrocarbon
derivatives held for hedging purposes was approximately $1 million at September
30, 2002. The value at risk related to hydrocarbon derivatives held for
non-hedging purposes was approximately $2 million at September 30, 2002.
In order to provide a more comprehensive view of the Company's commodity price
risk, a tabular presentation of open hydrocarbon derivatives is also provided.
The following table sets forth the future volumes and price ranges of
hydrocarbon derivatives held by the Company at September 30, 2002, along with
the fair values of those instruments.
-47-
Open Hydrocarbon Hedging Derivative Instruments (a)
(Thousands of dollars)
Fair Value
Asset
2002 2003 2004 2005 2006-2009 (Liability) (b)(c)
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Futures Positions
Volume (MMBtu) 1,460,000 - - - - $ 997
Average price, per MMBtu $ 3.50
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 2,660,500 7,978,000 7,241,000 7,218,000 21,677,000 $ 35,317
Average swap price, per MMBtu $ 2.60 $ 2.45 $ 2.33 $ 2.37 $ 2.47
Receive fixed price
Volume (MMBtu) 2,392,000 - - - - $ (3,021)
Average swap price, per MMBtu $ 2.77
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Basis Swap Positions
Volume (MMBtu) 1,794,000 4,745,000 - - - $ 1,138
Average price received, per MMBtu $ 3.82 $ 3.79
Average price paid, per MMBtu $ 3.62 $ 3.63
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Collar Positions
Volume (MMBtu) 22,186,000 5,956,000 268,500 - - $ (1,626)
Average ceiling price, per MMBtu $ 5.05 $ 4.64 $ 5.45
Average floor price, per MMBtu $ 3.36 $ 3.67 $ 2.82
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Option (Listed)
Call Volume (MMBtu) 180,000 180,000 - - - $ (1)
Average Call price $ 5.95 $ 6.35
Put Volume (MMBtu) (7,180,000) (180,000) $ 155
Average Put Price $ 2.87 $ 3.25
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Option (OTC)
Call Volume (MMBtu)
Average Call Price
Put Volume (MMBtu) 47,472 - - - - $ 26
Average Put Price $ 3.96
====================================================================================================================================
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Future position
Volume (Bbls) 308,000 320,000 - - - $ 2,307
Average price, per Bbl $ 23.44 $ 28.20
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Option
Put Volume (Bbls) 100,000 - - - - $ (242)
Average price, per Bbl $ 29.50
Call Volume (Bbls) (100,000) - - - - $ 130
Average price, per Bbl $ 25.85
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Collar Positions
Volume (Bbls) 70,364 152,000 90,000 - - $ (670)
Average ceiling price, per Bbl $ 28.62 $ 24.64 $ 26.21
Average floor price, per Bbl $ 21.32 $ 19.32 $ 18.67
====================================================================================================================================
(a) Positions reflect long (short) volumes.
(b) Includes $7,118 thousand net claims against counterparties with non-investment grade credit ratings.
(c) Includes $8,550 thousand in assumed liabilities which were capitalized as acquisition costs.
-48-
Open Hydrocarbon Non-Hedging Derivative Instruments (a)
(Thousands of dollars)
Fair Value
Asset
2002 2003 (Liability) (b)
--------------------------------------------------------------------------------- -------------- -------------------------
Natural Gas Futures Positions
Volume (MMBtu) 5,000,000 - $ 368
Average price, per MMBtu $ 3.88
---------------------------------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 7,240,000 - $ 1,291
Average swap price, per MMBtu $ 3.72
Receive fixed price
Volume (MMBtu) 5,926,717 1,055,347 $ (16,086)
Average swap price, per MMBtu $ 3.47 $ 2.99
---------------------------------------------------------------------------------------------------------------------------
Natural Gas Basis Swap Positions
Volume (MMBtu) 2,130,000 1,860,000 $ 1,145
Average price received, per MMBtu $ 5.53 $ 4.41
Average price paid, per MMBtu $ 5.05 $ 4.48
---------------------------------------------------------------------------------------------------------------------------
Natural Gas Option (Listed)
Call Volume (MMBtu) (16,000,000) - $ (29)
Average Call price $ 3.91
Put Volume (MMBtu) (3,000,000) - $ 127
Average Put Price $ 2.76
---------------------------------------------------------------------------------------------------------------------------
Natural Gas Option (Over the Counter)
Call Volume (MMBtu) (7,613,050) (3,055,200) $ (5,546)
Average Call price $ 5.29 $ 2.55
Put Volume (MMBtu) 380,000 - $ (77)
Average Put price $ 2.76
---------------------------------------------------------------------------------------------------------------------------
Natural Gas Spread Option (Over the Counter)
NYMEX / IFERC (c)
Put Volume (MMBtu) (4,080,000) (8,800,000) $ 573
Average Strike price $ 0.38 $ 0.32
===========================================================================================================================
---------------------------------------------------------------------------------------------------------------------------
Crude Oil Future position
Volume (Bbls) (257,000) - $ 2,147
Average price, per Bbl $ 29.51
---------------------------------------------------------------------------------------------------------------------------
Crude Oil Option
Put Volume (Bbls) - - $ 15
Average price, per Bbl
Call Volumes (Bbls) - - $ (32)
Average price, per Bbl
---------------------------------------------------------------------------------------------------------------------------
Crude Oil Option (Calender Spread)
Put Volume (Bbls) 100,000 400,000 $ (21)
Average price, per Bbl $ 0.39 $ 0.45
Call Volumes (Bbls) - (400,000) $ (31)
Average price, per Bbl $ 0.83
---------------------------------------------------------------------------------------------------------------------------
Crude Oil Swap Positions
Pay fixed price
Volume (Bbls) 11,850,006 - $ 10,068
Average swap price, per Bbl $ 27.45
Receive fixed price
Volume (Bbls) 12,077,000 - $ (16,688)
Average swap price, per Bbl $ 27.03
===========================================================================================================================
(a) Positions reflect long (short) volumes.
(b) Includes $1,931 thousand net claims against counterparties with non-investment grade credit ratings.
(c) Prices quoted from the New York Mercantile Exchange (NYMEX) and Inside FERC Gas Report (IFERC).
-49-
ITEM 4. CONTROLS AND PROCEDURES
Within the 90 days prior to the date of this report, the Company carried out an
evaluation of the effectiveness of the design and operation of the Company's
disclosure controls and procedures pursuant to Rule 13a-14 of the Securities
Exchange Act of 1934. Based upon that evaluation, the Chief Executive Officer
and Chief Financial Officer concluded that the Company's disclosure controls and
procedures are effective in timely identifying material information potentially
required to be included in the Company's SEC filings.
There were no significant changes in the Company's internal controls or other
factors that could significantly affect these controls subsequent to the date of
their evaluation and there were no corrective actions required with regard to
significant deficiencies and material weaknesses.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
See the information with respect to certain legal proceedings pending or
threatened against the Company previously reported in Item 3 of Unocal's amended
Annual Report on Form 10-K/A for the year ended December 31, 2001, in Item 1
of Part II of Unocal's Quarterly Report on Form 10-Q for the quarterly period
ended March 31, 2002, in Item 1 of Part II of Unocal's Quarterly Report on
Form 10-Q for the quarterly period ended June 30, 2002, and in Item 5 of
Unocal's Current Report on Form 8-K, dated September 18, 2002, under
"Myanmar Litigation". There is incorporated by reference: the information
regarding environmental remediation reserves and possible additional remediation
costs in notes 11 and 12 to the consolidated financial statements in Item 1 of
Part I of this report; the discussion of such amounts in the Environmental
Matters section of Management's Discussion and Analysis in Item 2 of Part I; and
the information regarding certain litigation and claims, tax matters and other
contingent liabilities in note 12 to the consolidated financial statements. See
also the discussion under "Reformulated Gasoline Patents" in the Outlook section
of Management's Discussion and Analysis of recent developments in certain
proceedings in which the Company is seeking to enforce its patents for
cleaner-burning gasolines.
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits: The Exhibit Index on page 55 of this report lists the
exhibits that are filed as part of this report.
(b) Reports on Form 8-K:
Filed during the third quarter of 2002:
(1) Current Report on Form 8-K, dated June 10, 2002, and filed July
29, 2002, for the purpose of reporting, under Item 5, the
Company's second quarter 2002 earnings, the commencement of
production from Phase II of the Pailin field in Thailand,
Agreements reached on Indonesia Geothermal Contracts, Agrium Inc.
Litigation, a Bangladesh-related claim and the Company's 2002
earnings forecast.
(2) Current Report on Form 8-K, dated and filed August 2, 2002, for
the purpose of reporting, under Item 5, Amendment No. 2 to the
Rights Agreement, dated as of August 2, 2002, between Unocal
Corporation and Mellon Investor Services LLC.
(3) Current Report on Form 8-K, dated August 12, 2002, and filed
August 13, 2002, for the purpose of reporting, under Item 9, the
certifications filed by the Company's chief executive officer and
chief financial officer.
(4) Current Report on Form 8-K, dated August 20, 2002, and filed
August 22, 2002, for the purpose of reporting, under Item 5, the
Company's offer to purchase the minority interest shares in its
Pure Resources, Inc. subsidiary.
(5) Current Report on Form 8-K, dated September 4, 2002, and filed
September 6, 2002, for the purpose of reporting, under Item 5,
the Company's third quarter and full year earnings forecast,
drilling results of its K-2 well and the mailing of the Pure
Resources exchange offer prospectus.
(6) Current Report on Form 8-K, dated September 13, 2002, and filed
September 18, 2002, for the purpose of reporting, under Item 5,
the downgrade by Moody's Investor Services, Inc. of the Company's
rating and senior unsecured debt.
(7) Current Report on Form 8-K, dated September 18, 2002, and filed
September 20, 2002, for the purpose of reporting, under Item 5,
an update relating to the Pure Resources exchange offer and a
litigation update regarding the Company's Myanmar cases.
(8) Current Report on Form 8-K, dated and filed September 25, 2002,
for the purpose of reporting, under Item 5, a hydrocarbon sheen
near Ranggas 6 location in Makassar Strait, Indonesia.
(9) Current Report on Form 8-K, dated and filed September 27, 2002,
for the purpose of reporting, under Item 5, a third quarter
environmental provision.
Filed during the fourth quarter of 2002 to the date hereof:
(10) Current Report on Form 8-K, dated October 1, 2002, and filed
October 2, 2002, for the purpose of reporting, under Item 5, a
revised exchange offer relating to Pure Resources.
(11) Current Report on Form 8-K, dated October 8, 2002, and filed
October 9, 2002, for the purpose of reporting, under Item 5, an
update on hurricane Lili and a revised exchange offer relating to
Pure Resources.
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(12) Amended Current Report on Form 8-K/A, dated September 27, 2002,
and filed October 11, 2002 for the purpose of reporting, under
Item 5, a third quarter environmental provision.
(13) Current Report on Form 8-K, dated October 23, 2002, and filed
October 24, 2002, for the purpose of reporting, under Item 5, the
Company's third quarter 2002 earnings, the Company's 2002
earnings forecast, the Company's 2003 and beyond production
outlook and the extension of the revised exchange offer relating
to Pure Resources.
(14) Current Report on Form 8-K, dated October 30, 2002, and filed
October 31, 2002, for the purpose of reporting, under Item 5, the
Company's acquisition of the remaining shares of Pure Resources
Inc., which it did not already own.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
UNOCAL CORPORATION
(Registrant)
Dated: November 12, 2002 By: /s/JOE D. CECIL
---------------------------------
Joe D. Cecil
Vice President and Comptroller
(Duly Authorized Officer
Principal Accounting Officer)
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CERTIFICATIONS
I, Charles R. Williamson, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Unocal Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report.
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared; (b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this quarterly report (the "Evaluation Date"); and (c) presented in
this quarterly report our conclusions about the effectiveness of the
disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function): (a) all significant deficiencies in the design or
operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial
data and have identified for the registrant's auditors any material
weaknesses in internal controls; and (b) any fraud, whether or not
material, that involves management or other employees who have a
significant role in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in the
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Dated: November 11, 2002
/s/CHARLES R. WILLIAMSON
-----------------------------
Charles R. Williamson
Chairman of the Board
and Chief Executive Officer
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CERTIFICATIONS
I, Terry G. Dallas, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Unocal Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report.
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared; (b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this quarterly report (the "Evaluation Date"); and (c) presented in
this quarterly report our conclusions about the effectiveness of the
disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function): (a) all significant deficiencies in the design or
operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial
data and have identified for the registrant's auditors any material
weaknesses in internal controls; and (b) any fraud, whether or not
material, that involves management or other employees who have a
significant role in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in the
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Dated: November 11, 2002
/s/TERRY G. DALLAS
----------------------------
Terry G. Dallas
Executive Vice President
and Chief Financial Officer
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EXHIBIT INDEX
10. Amendments and interpretations of certain compensation plans, effective
October 1, 2002.
12.1 Statement regarding computation of ratio of earnings to fixed charges of
Unocal Corporation for the nine months ended September 30, 2002 and 2001.
12.2 Statement regarding computation of ratio of earnings to fixed charges of
Union Oil Company of California for the nine months ended September 30,
2002 and 2001.
Copies of exhibits will be furnished upon request. Requests should be addressed
to the Corporate Secretary.
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